Method to reduce ghg emissions of fuel production

ABSTRACT

The present invention provides a method comprising carrying out an anaerobic digestion that produces biomethane and biogenic carbon dioxide and supplying the biogenic carbon dioxide for use in one or more enhanced oil or gas recovery operations. The biogenic carbon dioxide supplied to the one or more enhanced oil or gas recovery operations displaces the use of geologic carbon dioxide. Further provided is a method to reduce the life cycle GHG emissions associated with the production of a liquid fuel or fuel intermediate in a fuel production facility by providing such biomethane for use in the fuel production facility or associated utilities to supply energy. The present invention also relates to a method for receiving carbon dioxide at an enhanced oil or gas recovery site that has the GHG emission attributes of the biogenic carbon dioxide and using the received carbon dioxide to displace geologic carbon dioxide.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of provisional application No. 61/616,050, filed Mar. 27, 2012, provisional application No. 61/616,060, filed Mar. 27, 2012 and provisional application No. 61/715,541 filed Oct. 18, 2012, all of which are incorporated herein by reference.

TECHNICAL FIELD

The present invention relates to a method to reduce the life cycle greenhouse gas emissions associated with a process that transforms organic material into a fuel or a fuel intermediate.

BACKGROUND OF THE INVENTION

In recent years there has been significant concern about greenhouse gas (“GHG”) emissions and their effect on climate. GHGs, especially carbon dioxide, but also methane and nitrous oxide, trap heat in the atmosphere and thus contribute to climate change. One of the largest sources of GHG emissions is the production and use of fossil fuels for transportation, heating and electricity generation. Another significant source is as a byproduct of certain industrial processes, such as the production of ammonia, or the thermal decomposition of limestone in the manufacture of lime or cement.

Significant efforts have been devoted to reducing the GHG emissions that are associated with production and use of transportation fuels. Renewable fuels, for example, are being used to displace fossil fuels in the transportation sector. Ethanol is the most common renewable fuel, or “biofuel”, currently used for transportation, where it is commonly blended with gasoline at levels from 5% to 85% ethanol. Over 10 billion gallons of ethanol derived from corn were produced in the United States alone in 2010. Another renewable fuel that has been the subject of interest in recent years is biomethane, which is a component of biogas produced by decomposing waste organic material under anaerobic conditions.

Like any other fuel source containing carbon, combustion of renewable fuels such as ethanol releases carbon dioxide in the atmosphere. In addition, the process of fermenting plant derived organic material to produce the fuel will also produce carbon dioxide, which unless captured will enter the atmosphere. These carbon dioxide inputs, however, are considered relatively benign, given that they simply return to the atmosphere carbon that was previously removed therefrom by plant photosynthesis. More generally, this relatively benign nature is also true of carbon dioxide released due to the combustion, processing or decay of plant matter and other organic material or biological sources, where the underlying carbon had previously been removed from the atmosphere by photosynthesis. Carbon dioxide from such biological sources is generally referred to as “biogenic carbon dioxide.”

Although an unwanted by-product of combustion, carbon dioxide has substantial industrial uses. For example, it is a raw material for the synthesis of various chemicals and polymers, and is used for dry cleaning and as a solvent for organic compounds. In the production of petroleum, carbon dioxide is injected into wells in declining oil fields to enhance the recovery of additional oil remaining in the oil fields. Carbon dioxide enhanced oil recovery places the gas into under-producing or non-producing oil-bearing geologic formations to increase the mobility of the oil, thus aiding in its recovery. Carbon dioxide has also been placed underground to enhance the recovery of natural gas (referred to herein as “gas”) from gas-bearing geologic formations.

There are various non-biogenic commercial sources of carbon dioxide for industrial use. One source is as a by-product of other industrial processes, such as the production of ammonia or hydrogen. Another industrial source is from boilers burning fossil fuels. Along with carbon dioxide produced from fossil fuel combustion, carbon dioxide from such industrial processes is referred to as “anthropogenic carbon dioxide.” Unlike biogenic carbon dioxide, release of anthropogenic carbon dioxide into the atmosphere is generally thought to increase concentrations of atmospheric carbon dioxide, life cycle GHG emissions and thereby have an effect on the climate because the underlying carbon is of fossil not atmospheric origin.

A second non-biogenic source of carbon dioxide for industrial use is that which originates from underground reservoirs or deposits. This type of carbon dioxide is produced underground from natural processes. Carbon dioxide from this second source is referred to as “geologic carbon dioxide.” Like anthropogenic carbon dioxide, release of geologic carbon dioxide into the atmosphere is generally thought to increase concentrations of atmospheric carbon dioxide and life cycle GHG emissions, and thereby have an effect on the climate.

A life cycle analysis is often used to determine the overall level of GHG emissions related to a particular fuel. Such life cycle analyses seek to account for the GHG fluxes associated with each stage of the development, production, delivery and use of the fuel. Biofuels are derived from organic material that contains carbon removed from the atmosphere during photosynthesis. In life cycle analyses, the carbon dioxide removed from the atmosphere during photosynthesis is credited against the carbon dioxide released during combustion, leading to lower net levels of GHG emissions. By contrast, fossil fuels such as petroleum or coal are extracted from beneath the earth, and, when they are burned, release carbon into the atmosphere, which adds to total atmospheric GHG.

It is understood by those skilled in the art that methods for calculating life cycle carbon dioxide emissions can slightly vary. In calculating carbon dioxide life cycle emissions under certain methods, biogenic carbon dioxide is not considered to contribute to GHG life cycle emissions since the total biogenic carbon dioxide generated from fermentation, combined with the carbon dioxide from fuel combustion, is equal to and is offset by the atmospheric carbon dioxide removed by the plant, via photosynthesis, to make organic molecules. The United States government, through the Energy Independence and Security Act (“EISA”) of 2007, has promoted the use of renewable fuels with reduced GHG emissions. Some of the purposes of the act are to increase the production of clean renewable fuels, to promote research on and deploy GHG capture and to reduce fossil fuels present in transportation fuels. The act sets out a Renewable Fuels Standard (“RFS”) with increasing annual targets for the renewable content of transportation fuel sold or introduced into commerce in the United States. The RFS mandated volumes are set by four nested fuel category groups, namely renewable biofuel, advanced biofuel, biomass-based diesel, and cellulosic biofuel, which require at least 20%, 50%, 50% and 60% GHG reductions relative to gasoline, respectively. The United States Environmental Protection Agency (“EPA”) conducts life cycle analyses to determine whether or not renewable fuels produced under varying conditions will meet these GHG thresholds.

The mandated annual targets of renewable content in transportation fuel under the RFS are implemented using a credit called a Renewable Identification Number, referred to herein as a “RIN”, to track and manage the production, distribution and use of renewable fuels for transportation purposes. RINs can be likened to a currency used by obligated parties to certify compliance with mandated renewable fuel volumes. The EPA is responsible for overseeing and enforcing blending mandates and developing regulations for the generation, trading and retirement of RINs.

In addition to EISA, numerous jurisdictions, such as the state of California, the province of British Columbia, Canada and the European Union, have set annual targets for reduction in average life cycle GHG emissions of transportation fuel. Such an approach is often referred to as a Low Carbon Fuel Standard (“LCFS”), where credits may be generated for the use of fuels that have lower life cycle GHG emissions than a specific baseline fuel. Such fuels are often referred to as having a lower “carbon intensity” or “CI”.

Various forms of carbon dioxide sequestration have been proposed for storage of carbon dioxide, including geologic sequestration, which involves injecting carbon dioxide directly into underground geological formations. Thus, it has been thought that injecting carbon dioxide into oil or gas fields to assist oil or gas recovery effectively contains or sequesters the carbon dioxide by containing it in geological formations. However, there are uncertainties regarding what fraction of the carbon dioxide injected into such underground geological formations is sequestered permanently, and what fraction might leak out over time. Leakage of carbon dioxide can occur through breaches in the integrity of geologic formations, through active or abandoned well bores, which tend to be numerous in oil or gas fields, or via equipment leakages.

The EPA has recently introduced regulations requiring GHG monitoring and reporting for any well or group of wells that injects carbon dioxide into underground geological formations for sequestration, or for other applications. At present, under the regulations, there is a requirement for wells that sequester carbon dioxide to develop and implement an EPA-approved monitoring, reporting and verification plan. Some of the requirements of the plan are to identify potential leakage pathways of carbon dioxide and to include a strategy for detecting and quantifying such leakage. After approval of the plan by the EPA, there is a requirement to monitor the amount of carbon dioxide sequestered, which involves subtracting the amount that leaks, by the methodology as set out in the plan, and then reporting these values annually to the EPA. Furthermore, under other EPA regulations implemented with respect to an underground injection control program, there is a requirement for post-injection monitoring during the period after carbon dioxide injection ceases, but prior to site closure to ensure protection of underground sources of drinking water. The duration of post-injection monitoring defined in the rule is 50 years following the cessation of injection.

The stringent and complicated reporting requirements of these two regulations increase the operating cost of facilities that sequester carbon dioxide and could add risk if loss of containment leads to invalidation of credits or RINS generated relying on sequestration.

The potential for carbon dioxide leakage has accordingly impaired the economic feasibility of carbon dioxide sequestration in geological formations as a means of reducing the measured life cycle GHG emissions.

Given the undisputable concern with carbon dioxide's deleterious effects on climate, but given the indisputable industrial role for carbon dioxide in modern society, there is a pressing need to satisfy that role in a more environmentally benign manner. There is a need in the art for a cost-effective technology to enable biofuel producers to reduce GHG emissions and preferably contribute to reducing GHG emissions to levels that are at least about 50% lower than a “gasoline baseline”, which is a value representing the life cycle GHG emissions for gasoline set by government authorities. There is a further need to enable producers of a fuel, or an intermediate thereof, produced by fermentation to qualify for desired credits associated with reduced GHG life cycle emissions, including for RINs under EISA having higher market value and associated with lower GHG emissions.

SUMMARY OF THE INVENTION

The present invention provides a method to reduce the life cycle GHG emissions associated with a process that transforms organic material by fermentation into a fuel or a fuel intermediate. It overcomes, ameloriates, or provides useful alternatives in relation to known methods. The methods disclosed herein overcome limitations of prior or existing methods for reducing life cycle GHG emissions that rely on recovering and using carbon dioxide produced in fermentation. Such existing methods either do not achieve net reductions in carbon dioxide emissions or lead to uncertain levels of savings that cannot be assured or add costs or potential liabilities to operations.

According to one aspect of the invention, there is provided a method comprising fermenting organic material in an anaerobic digestion to produce biogas comprising biomethane and biogenic carbon dioxide; separating the biomethane and biogenic carbon dioxide; collecting an amount of biogenic carbon dioxide produced from the step of separating; and supplying the biogenic carbon dioxide for use in one or more enhanced oil or gas recovery operations. The carbon dioxide supplied to the one or more enhanced oil or gas recovery operations displaces the use of geologic carbon dioxide. According to one embodiment of the invention, the life cycle GHG emissions associated with the production or use of the biomethane are reduced relative to a “biomethane production process baseline” as a result of the displacement of geologic carbon dioxide. The biomethane production process baseline refers to the life cycle GHG emissions associated with a biogas production process conducted under identical conditions except the biogenic carbon dioxide that is separated from the biomethane is released to the atmosphere.

The present invention also provides a method to reduce the life cycle GHG emissions associated with the production of a liquid fuel or fuel intermediate, for example, but not limited to, ethanol or other alcohols. The method comprises producing sugar from plant derived organic material and converting the sugar to the liquid fuel or fuel intermediate in a fuel production facility. Methane is used to supply energy to the fuel production facility, or associated utilities. Beneficially, the methane that is supplied to the facility and/or the utilities has associated with it life cycle GHG emissions that are reduced relative to a biomethane production process baseline. The life cycle GHG emission reduction of the methane results from carrying out the previously described method for reducing life cycle GHG emissions associated with the production of biomethane relative to a biomethane production process baseline. The liquid fuel or fuel intermediate produced by the fuel production facility has reduced life cycle GHG emissions due to the use of such methane to supply energy. In one embodiment, the methane having associated reduced life cycle GHG emissions is provided by a third party.

As discussed above, when carbon dioxide is placed underground in geological formations to recover oil or gas, there is the potential that a certain fraction will leak over time. Because geologic carbon dioxide originates from underground reservoirs or deposits, when this type of carbon dioxide leaks from geological formations, the resultant emissions need to be accounted for in life cycle GHG life calculations. However, it can be difficult to quantify with precision the fraction of carbon dioxide released to the atmosphere and the fraction which is captured and removed from the atmosphere. This in turn can lead to uncertainties when calculating life cycle GHG emissions. By displacing geologic carbon dioxide with biogenic carbon dioxide in accordance with the invention, life cycle GHG emissions calculations need not account for the degree to which carbon dioxide is either leaked or permanently sequestered; in all cases, the credits and debits of typical GHG accounting lead to a GHG saving equal to the amount of biogenic carbon dioxide collected and used in the enhanced oil or gas recovery site. That is, the saving occurs independently of the proportion of the carbon dioxide that leaks from the enhanced oil or gas recovery site and the proportion that is permanently sequestered or remaining underground.

When biogenic carbon dioxide is used in enhanced oil or gas recovery without displacement of geologic carbon dioxide, the savings are lower and must account for the leakage. Further, the measurement of leakage is often difficult and costly or can lead to potential future liabilities.

A life cycle GHG emission analysis for using only biogenic carbon dioxide in an enhanced oil or gas recovery without the use of the invention is described below. In this non-limiting example, if for a given amount of carbon dioxide introduced into an enhanced oil or gas recovery site (typically measured as a flow rate), the percentage of carbon dioxide ultimately leaked to the atmosphere is X %, then the remainder of the introduced amount (100%−X %) is not leaked, i.e., left underground. A life cycle analysis of the carbon dioxide emissions related to the use of 100 units of biogenic carbon dioxide in an EOR operation, without implementing the invention may include:

-   -   (a) a credit for the amount of biogenic carbon dioxide collected         and used in enhanced oil or gas recovery (100 units); and     -   (b) a debit for emissions related to biogenic carbon dioxide         that is leaked (X units, given leakage is X % of the input         flow).

In the above case, the net GHG impact is an improvement of 100−X and the amount of carbon dioxide remaining underground in the foregoing life cycle analysis needs to account for X % leakage. However, as discussed, there are uncertainties in determining the amount of leakage from an enhanced oil or gas recovery site. Further, monitoring requirements set by government authorities can be stringent and complicated. To confirm the benefits and to acquire recognized benefits, one would typically need to conduct a monitoring, recording and verification plan such as is required under the US EPA's Mandatory Greenhouse Gas Reporting Program, Title 40, Part 98, Subpart RR §98.448. Additionally, if this process is used to generate credits, leakage subsequent to the issue of the credits could lead to liabilities for the generator of the credits because the credits are reliant upon and related to the amount of carbon dioxide that is retained and not leaked.

By contrast, the life cycle analysis of the method of the invention does not need to account for such leakage.

A life cycle analysis of the method of the invention involving the displacement of 100 units of geologic carbon dioxide with 100 units of biogenic carbon dioxide, comprised of calculating the emissions impact of the disposition of the biogenic carbon dioxide and crediting the emissions impact of the displaced geologic carbon dioxide, may include:

-   -   (a) a credit for the amount of biogenic carbon dioxide collected         and used in the enhanced oil or gas recovery site (100 units);     -   (b) a debit for the amount of biogenic carbon dioxide that is         leaked from said site (X units, given leakage is X % of the         input flow); and     -   (c) a credit for the emissions impact of the avoided amount of         geologic carbon dioxide, equal to X units, comprised of the         following:         -   (i) emissions related to geologic carbon dioxide that would             have been leaked from the use of the same amount of geologic             carbon dioxide (X units, given leakage is X % of the input             flow); and         -   (ii) zero net emissions for geologic carbon dioxide that             would have been remaining underground from the use of the             same amount of geologic carbon dioxide, because such             geologic carbon dioxide would have been originally extracted             from underground and then returned underground in the             enhanced oil recovery region, thus providing no net             emissions impact (quantity 100−X, given leakage is X % of             the input flow).

The net GHG benefit when implementing the invention would be calculated as the credit in (a) (100 units) minus the debit in (b) (X units) plus the credit in (c) (X units), i.e., 100−X+X=100. The debit in (b) is offset by the credit in (c), and thus the overall net reduction in emissions (100 units, in this example) is independent of the amount of carbon dioxide that is leaked in the system. That is to say, the emission calculations need not take into account the relative amounts either leaked or permanently sequestered in the enhanced oil or gas recovery operation.

Thus, the invention avoids complicated or burdensome long term leakage monitoring, verification and reporting requirements and the associated costs. Additionally, the invention delivers greater net GHG savings compared to systems that do not benefit from the geologic carbon dioxide displacement and avoids potential liabilities that could be incurred with leakage.

The invention is not bound to any one particular method for use in calculating life cycle GHG emissions. In life cycle analyses, the energy consumed and emissions generated by a fuel production process, for example, an ethanol plant, would be allocated not only to the fuel, but also to each of the by-products and there are a number of methods that can be used to estimate by-product allocations. These include methods that account for the energy usage of each by-product, based on engineering analysis of the processes related to each by-product. As would be understood by those skilled in the art, the life cycle net carbon emissions associated with a fuel or fuel intermediate would be calculated and data generated in accordance with the prevailing applicable guidelines which may vary by regulatory standard or change over time. The guidelines for such calculations would be known to those skilled in the art.

The reductions in life cycle GHG emissions result from the displacement of geologic carbon dioxide with biogenic carbon dioxide. Reductions in life cycle GHG emissions are not achieved when the biogenic carbon dioxide is being used to displace anthropogenic carbon dioxide because displacing anthropogenic carbon dioxide cannot yield any credit associated with avoiding release of carbon dioxide since the carbon dioxide will be released to the atmosphere if it is not used in the enhanced oil or gas recovery operation.

The enhanced oil recovery operation is any facility, apparatus, or system that enables the recovery of underground oil with the aid of fluid injection, including liquid or gas injection. Preferably, liquid injection is employed. The enhanced oil recovery may include the use of cyclic or continuous water, steam, steam flooding and fire flooding. Optionally, the enhanced oil recovery operation also employs microbial injection or thermal recovery in combination with fluid injection. The fluid injection may be considered a chemical injection. Furthermore, the fluid injection may be part of a hydraulic fracturing operation to recover underground oil.

The enhanced gas recovery operation is any facility, apparatus or system that enables the recovery of underground natural gas with the aid of fluid injection. The gas may be recovered via any process known to those of skill in the art that involves recovering natural gas through injection of carbon dioxide. The fluid injection may optionally be part of a hydraulic fracturing operation to recover underground natural gas, as described below.

According to one aspect of the present invention, there is provided a method that comprises: (i) anaerobically digesting organic material to produce biogas comprising biomethane and biogenic carbon dioxide; (ii) separating the biomethane and biogenic carbon dioxide; (iii) collecting an amount of the biogenic carbon dioxide generated from the step of separating; and (iv) supplying the biogenic carbon dioxide from step (iii) for use in one or more enhanced oil or gas recovery operations for displacement of geological carbon dioxide, wherein the life cycle GHG emissions associated with the production of the biomethane are reduced relative to a biomethane production process baseline by at least 1.5 g CO₂/MJ as a result of the displacement of geologic carbon dioxide. According to further embodiments of the present invention, the biogenic carbon dioxide is used to displace geologic carbon dioxide in at least one site that injects carbon dioxide to facilitate enhanced oil or gas recovery. For example, in some embodiments, at some point in time during the lifetime of an enhanced oil or gas recovery operation, geologic carbon dioxide would be taken out of use and biogenic carbon dioxide would be used instead to facilitate oil recovery. For example, the displacement may result from taking out of use a first amount of geologic carbon dioxide at the one or more enhanced oil or gas recovery sites and subsequently supplying an amount of biogenic carbon dioxide at the one or more enhanced oil or gas recovery sites to substitute the first amount of geologic carbon dioxide.

According to a further aspect of the invention, the aforesaid collection of biogenic carbon dioxide and use in accordance with the invention provides a reduction in the life cycle GHG emissions associated with the fuel or fuel intermediate. A life cycle analysis of net carbon emissions associated with such production may include:

-   -   (a) a credit for the amount of biogenic carbon dioxide collected         and used underground in the enhanced oil recovery operation;     -   (b) a debit for the amount of biogenic carbon dioxide that         re-enters the atmosphere as a result of fugitive emissions from         the ground; and     -   (c) a credit for the amount of geologic carbon dioxide that did         not enter that atmosphere as a result of fugitive emissions from         the well.

The debit in (b) is offset by the credit in (c) and thus the overall net reduction in emissions need not take into account any deductions for fugitive emissions.

According to a further aspect of the invention, there is provided a method for reducing life cycle GHG emissions associated with the production of biomethane, the method comprising: (i) anaerobically digesting organic material to produce biogas comprising biomethane and biogenic carbon dioxide; (ii) separating the biomethane and biogenic carbon dioxide; (iii) collecting an amount of the biogenic carbon dioxide generated from the step of separating; and (iv) reducing the life cycle GHG emissions associated with the biomethane, the reducing being achieved at least in part by a displacement of geologic carbon dioxide with the biogenic carbon dioxide from step (iii), the displacement resulting from: (a) introducing the biogenic carbon dioxide into an apparatus for transporting carbon dioxide to one or more enhanced oil or gas recovery sites that used or are using geologic carbon dioxide; (b) supplying the biogenic carbon dioxide for use in one or more enhanced oil or gas recovery sites that used or are using geologic carbon dioxide; or (c) both (a) and (b). Preferably, the life cycle GHG emissions associated with the production of the biomethane are reduced relative to a biomethane production process baseline by at least 1.5 g CO₂/MJ relative as a result of the displacement of geologic carbon dioxide.

According to another aspect of the invention, there is provided a method to reduce the life cycle GHG emissions associated with production of biomethane, the method comprising: (i) anaerobically digesting organic material to produce biogas comprising biomethane and biogenic carbon dioxide; (ii) separating the biomethane and biogenic carbon dioxide; (iii) collecting an amount of biogenic carbon dioxide generated from the step of separating; and (iv) introducing the biogenic carbon dioxide into apparatus for transporting said biogenic carbon dioxide to one or more enhanced oil or gas recovery sites, wherein in respect of at least one or more of the sites at least two conditions are met selected from: (a) the site has used geologic carbon dioxide in its enhanced oil or gas recovery; (b) the site has access to geologic carbon dioxide for use in its enhanced oil or gas recovery; and (c) written documentation indicates or reflects that biogenic carbon dioxide is used to displace geologic carbon dioxide. In one embodiment of the invention, at least written documentation indicates or reflects that biogenic carbon dioxide is used to displace geologic carbon dioxide.

In a further aspect of the invention, there is provided a method to reduce the life cycle GHG emissions associated with production of biomethane, the method comprising: (i) anaerobically digesting plant derived organic material to produce biogas comprising biomethane and biogenic carbon dioxide; (ii) separating the biomethane and biogenic carbon dioxide; (iii) collecting an amount of biogenic carbon dioxide generated from the step of separating; and (iv) introducing the biogenic carbon dioxide of step (iii) into apparatus for transporting said biogenic carbon dioxide to one or more enhanced oil or gas recovery sites, wherein, in respect of at least one of the sites, written documentation indicates or reflects that biogenic carbon dioxide is being used to displace geologic carbon dioxide at the site.

The method may further comprise generating a renewable fuel credit associated with the liquid fuel or fuel intermediate. The term “credit” or “renewable fuel credit” means any rights, credits, revenues, offsets, greenhouse gas rights or similar rights related to carbon credits, rights to any greenhouse gas emission reductions, carbon-related credits or equivalent arising from emission reduction trading or any quantifiable benefits (including recognition, award or allocation of credits, allowances, permits or other tangible rights), whether created from or through a governmental authority, a private contract or otherwise. According to one embodiment of the invention, the renewable fuel credit is a certificate, record, serial number or guarantee, in any form, including electronic, which evidences production of a quantity of fuel meeting certain life cycle GHG emission reductions relative to a baseline set by a government authority. Preferably, the baseline is a gasoline baseline. Non-limiting examples of credits include RINs and LCFS credits.

According to another aspect of the invention, there is provided a method to reduce the life cycle GHG emissions associated with production of a liquid fuel or fuel intermediate, the method comprising: (i) producing sugar from plant derived organic material and converting the sugar to the liquid fuel or fuel intermediate in a fuel production facility; and (ii) receiving methane to supply energy to the fuel production facility or associated utilities, wherein the methane has associated with it life cycle GHG emissions that are reduced relative to a biomethane production process baseline as a result of one or more third parties producing the methane by a process comprising: (a) anaerobically digesting organic material to produce biogas comprising methane and biogenic carbon dioxide; (b) separating the methane and biogenic carbon dioxide; (c) collecting an amount of the biogenic carbon dioxide generated from the step of separating; (d) supplying the biogenic carbon dioxide from step (c) for use in one or more enhanced oil or gas recovery sites for displacement of geologic carbon dioxide; and (e) supplying the biomethane to an apparatus for delivering methane to one or more fuel production facilities. Preferably, the method further comprises generating a renewable fuel credit associated with the liquid fuel or fuel intermediate.

According to one embodiment of the invention, an amount of biogenic carbon dioxide generated from the step of converting the sugar to the liquid fuel or fuel intermediate in the fuel production facility is collected and supplied for use in one or more enhanced oil or gas recovery sites for displacement of geological carbon dioxide.

According to one embodiment of the invention, the methane that is used to supply energy in any part of the fuel production facility or associated utilities is withdrawn from a natural gas pipeline containing methane from sources other than from the anaerobic digestion of organic material. The methane may be used to supply energy in the form of heat or electricity.

The present invention also provides methods for generating or receiving data relating to a life cycle GHG emission analysis of a liquid fuel or fuel intermediate having reductions in life cycle GHG emissions due to the practice of the invention. As used herein, the term “data” refers to information in numerical format. The data may be stored in digital format in a storage medium used to retain digital data.

As used herein, “data relating to”, includes any data that would be inputted to a life cycle GHG emission analysis of a fuel or fuel intermediate or any data that uses values reliant upon or calculated from the life cycle GHG emission analysis. Examples of data that is inputted to a life cycle GHG emission analysis includes the following: GHG emissions in production and recovery of the fuel or fuel intermediate, energy use associated with feedstock transportation, emissions from fuel or fuel intermediate production, transport and storage of the fuel or fuel intermediate prior to its use in transportation or for heating, and the like. Examples of data that use values reliant upon or calculated from a life cycle GHG emission analysis include one or more of the following: the weight amount (e.g., in tonnes) of carbon dioxide emissions reduced by the practice of the invention; the volumes (e.g., in gallons) of fuel or fuel intermediate produced or generated using the process of the invention to reduce GHG emissions; the aggregate number or rate of credits generated as a result of using the process of the invention to reduce GHG emissions; and data describing the eligibility of the process of the invention for credits such as database fields identifying the process through a numerical value.

Further provided herein is a method to reduce the life cycle GHG emissions associated with a process that transforms plant derived organic material into a liquid fuel or a fuel intermediate, the method comprising: (i) producing sugar from plant derived organic material and converting the sugar to the liquid fuel or fuel intermediate in a fuel production facility; (ii) receiving methane to supply energy to the fuel production facility or associated utilities, wherein the methane has associated with it life cycle GHG emissions that are reduced relative to a biomethane production process baseline as a result of producing the methane by a process comprising: (a) anaerobically digesting organic material to produce biogas comprising methane and biogenic carbon dioxide; (b) separating the methane and biogenic carbon dioxide; (c) collecting an amount of the biogenic carbon dioxide generated from the step of separating; (d) supplying the biogenic carbon dioxide from step (c) for use in one or more enhanced oil or gas recovery sites for displacement of geologic carbon dioxide; and (e) supplying the biomethane to an apparatus for delivering methane to one or more fuel production facilities; (iii) preparing or receiving data relating to a life cycle GHG emission analysis of the fuel or fuel intermediate, which life cycle GHG emission analysis includes a quantification of a GHG emission reduction due to a reduction in the use of geologic carbon dioxide in the one or more enhanced oil or gas recovery sites that occurred or would occur over the lifetime of the one or more sites as a result of the use of biogenic carbon dioxide; and (iv) generating a renewable fuel credit associated with the liquid fuel or fuel intermediate. Preferably, a third party carries out steps (a)-(e).

Further provided herein is a method to reduce the life cycle GHG emissions associated with a process that transforms plant derived organic material into a liquid fuel or a fuel intermediate, the method comprising: (i) producing sugar from plant derived organic material and converting the sugar to the liquid fuel or fuel intermediate in a fuel production facility; (ii) receiving methane to supply energy in any part of the fuel production facility or associated utilities, wherein the methane has associated with it life cycle GHG emissions that are reduced relative to a biomethane production process baseline as a result of producing the methane by a process comprising: (a) anaerobically digesting organic material to produce biogas comprising methane and biogenic carbon dioxide; (b) separating the methane and biogenic carbon dioxide; (c) collecting an amount of the biogenic carbon dioxide generated from the step of separating; (d) supplying the biogenic carbon dioxide from step (c) for use in one or more enhanced oil or gas recovery sites for displacement of geologic carbon dioxide; and (e) supplying the biomethane to an apparatus for delivering methane to one or more fuel production facilities, wherein the life cycle GHG emissions associated with the production of the biomethane are reduced by at least 1.5 g CO₂ eq/MJ relative to a biomethane production process baseline as a result of displacement; (iii) recovering the liquid fuel or fuel intermediate produced in the fuel production facility (iv) generating or receiving data relating to a life cycle GHG emission analysis of the liquid fuel or fuel intermediate. Preferably, a third party carries out steps (a)-(e).

According to certain embodiments, the invention provides a means for producing fuel ethanol in the fuel production facility from wheat or sorghum having life cycle GHG emissions that are at least 50% below those of gasoline. Such fuel ethanol could be eligible for categorization as a fuel meeting the GHG reduction thresholds and other criteria set by current United States EISA legislation required for qualification as an advanced biofuel. In such an embodiment, the ethanol produced in accordance with the invention would qualify for generation of a RIN having a D code of 5, referred to herein as a “D5 RIN”. Although the fuel that qualifies for a D5 RIN may be ethanol produced from wheat or sorghum, other fuels produced from organic materials may qualify as well.

Also provided is a method for arranging for a corn ethanol production facility to produce a fuel or fuel intermediate having a D5 RIN credit associated therewith, the method comprising advising the corn ethanol production facility to carry out the method of the invention as described above to reduce the GHG emissions associated with the fuel or fuel intermediate to a level sufficient to qualify for a D5 RIN or a RIN lower than 6. Such method may further comprise advising the corn ethanol production facility to switch from corn to wheat or sorghum as the feedstock.

Further provided herein is a method for generating a D5 RIN credit associated with ethanol produced in an ethanol production facility, said method comprising switching feedstock supplied to the ethanol production facility from corn starch to a non-corn starch feedstock and carrying out any one of the foregoing methods to reduce the life cycle GHG emissions of the ethanol to a level relative to a gasoline baseline sufficient to qualify for the D5 RIN credit.

In addition, the method of the invention may allow for the production of fuel with life cycle GHG emissions that aids obligated parties in meeting established targets for GHG emission reductions in jurisdictions with legislation directed to an LCFS.

The present invention also provides a method comprising: (i) receiving carbon dioxide at an enhanced oil or gas recovery site, the carbon dioxide being withdrawn from an apparatus into which biogenic carbon dioxide is fed, which biogenic carbon dioxide is produced by any one of the foregoing methods; and (ii) using the received carbon dioxide to displace geologic carbon dioxide at the site. Preferably, a third party supplies the carbon dioxide received at the enhanced oil or gas recovery site.

Further provided herein is a method comprising the steps of: (a) receiving carbon dioxide at an enhanced oil or gas recovery site, the carbon dioxide being withdrawn from an apparatus into which biogenic carbon dioxide derived from an anaerobic digestion has been fed; and (b) using the received carbon dioxide to displace geologic carbon dioxide. The method may further comprise causing a third party to feed the carbon dioxide derived from the anaerobic digestion to the apparatus.

The received carbon dioxide has the GHG emission attributes of the biogenic carbon dioxide derived from the anaerobic digestion. By this it is meant that the withdrawn carbon dioxide qualifies as biogenic carbon dioxide despite the fact that it may originate from non-organic material. As is the case for biogenic carbon dioxide, leakages of such carbon dioxide to the atmosphere during or after its use in the enhanced oil or gas recovery, is not quantified as a GHG emission in life cycle GHG emission calculations. That is, the carbon dioxide withdrawn from such apparatus is considered to have the GHG emission value of the biogenic carbon dioxide introduced to the apparatus, even though the carbon dioxide may not contain actual molecules from the original organic material from which the carbon dioxide is derived, but rather the energy equivalent. As discussed further herein, for such GHG emission attributes to be recognized, the amount of carbon dioxide introduced to the apparatus and the amount withdrawn typically should be the same and may be evidenced by written documentation. However, according to some embodiments, the invention is not constrained by the exact amounts of carbon dioxide introduced to the apparatus and the amounts withdrawn, and whether such amounts correspond.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a comparison of the life cycle GHG emissions for a gasoline baseline and ethanol produced from a fermentation of sugar, where such sugar is derived from grain sorghum. Bar A is the gasoline baseline; bar B is a production process baseline in which ethanol is produced from the fermentation of sugar from grain sorghum and in which the biogenic carbon dioxide from the fermentation is not collected; and bar C is a process in which biogenic carbon dioxide is collected from the fermentation and used to displace geologic carbon dioxide in an enhanced oil or gas recovery in accordance with embodiments of the invention.

FIG. 2 is a comparison of the life cycle GHG emissions for a gasoline baseline and ethanol produced from a fermentation of sugar, where such sugar is derived from grain sorghum. Bar A is the gasoline baseline; bar B is a production process baseline for the ethanol; bar C is ethanol produced from a process in which methane used for energy in the ethanol production process originates from an anaerobic digestion which produces biomethane and biogenic carbon dioxide and in which carbon dioxide is not collected (biomethane production process baseline); and bar D is ethanol from a process in which the methane used in the production process originates from an anaerobic digestion which produces biomethane and biogenic carbon dioxide and in which biogenic carbon dioxide is collected and used to displace geologic carbon dioxide in enhanced oil or gas recovery in accordance with embodiments of the invention.

DETAILED DESCRIPTION OF THE INVENTION

The following description is of a preferred embodiment by way of example only and without limitation to the combination of features necessary for carrying the invention into effect. The headings provided are not meant to be limiting of the various embodiments of the invention.

Organic Material

The first step in the present invention is to produce biogenic carbon dioxide. Any suitable biologic source material derived from plants or animals can be used as the organic material in the method of the invention to provide a carbon and/or energy source for the fermentation to produce biogenic carbon dioxide. This includes plant derived organic material comprising polysaccharides, including starch, cellulose and hemicellulose, oligosaccharides, disaccharides, monosaccharides, or a combination thereof. Other biologic source material that can be utilized as a carbon and/or energy source for the fermentation includes compounds or molecules derived from organic material, such as lignin and fats.

According to a preferred embodiment of the invention, the plant derived organic material includes material comprising starches, sugars or other carbohydrates, including sugar and starch crops. The sugar and starch crops may include, but are not limited to, corn, wheat, barley, rye, sorghum, rice, potato, cassaya, sugar beet, sugar cane, or a combination thereof. In a preferred embodiment, the sugar or starch crop is not corn starch. According to some embodiments, if the fuel is ethanol, the organic material is not corn starch. According to such an embodiment, the plant derived organic material includes wheat, barley, rye, sorghum, rice, potato, cassaya, sugar beet, sugar cane or a combination thereof. Preferably, the plant derived organic material is wheat or sorghum.

According to some embodiments of the invention, the organic material originates from a waste stream such as landfill material, including food and yard waste that may or may not be intermixed with non-organic components of landfill material; agricultural waste, including animal waste material such as manure; slaughterhouse waste and fish waste, waste from plant operations, including sewage sludge, still bottoms or other waste streams from fermentation plants; or a combination thereof.

It is possible, but less preferred, to use lignocellulosic feedstock as the organic material, such as agricultural residues for example, soybean stover, corn stover, rice straw, sugar cane straw, rice hulls, barley straw, corn cobs, wheat straw, canola straw, oat straw, oat hulls, corn fiber or a combination or derivative thereof; cultivated crops, for example, grasses such as C4 grasses; sugar processing residues, for example, bagasse, such as sugar cane bagasse, beet pulp or a combination or derivative thereof; and woody plant biomass such as forestry products.

Preparation of the Organic Material for Fermentation

Prior to fermentation, the organic material may be processed by mechanical, chemical, thermal and/or biological processes. Fermentable material may be obtained from source material using techniques that are known to those of ordinary skill in the art, including, but not limited to those described below.

In some embodiments of the invention, plant derived organic material is processed to produce sugar. The sugar in turn is fermented to produce the fuel or fuel intermediate. Sugar crops, including, but not limited to, sugar cane, sugar beets or sweet sorghum, may be subjected to a mechanical treatment, such as crushing and/or pressing, to extract the sugar from the plants. For example, sucrose from sugar cane can be extracted using roller mills. Sugar from sweet sorghum stalks can be extracted in a similar manner, although certain varieties of sorghum contain grain that can be processed using technology employed for processing starch crops as described below.

Starch crops, which include cereal crops, may be subjected to size reduction, such as by milling or grinding. The starch may be subsequently hydrolyzed with enzymes, by chemical treatment, or some combination of these treatments. By way of example, grain may be milled with a roller or hammer mill, followed by the addition of water and hydrolysis of the starch with amylase to produce fermentable sugar. This method is commonly referred to as “dry milling”. An alternative method is wet milling in which the grain is steeped, such as in an acidic solution and/or a solution containing enzymes, and then subjected to size reduction, such as milling, to facilitate separation of the starch from the other components of the grain. The starch is subsequently hydrolyzed to sugar using methods described above.

The production of fermentable sugar from lignocellulosic feedstocks can be carried out by any of a variety of techniques know to those of skill in the art. For example, pretreatment followed by hydrolysis involving enzymatic or chemical treatment including by acid or alkali treatment, can be utilized.

Those of ordinary skill understand that the embodiments and examples discussed herein are non-limiting, and accordingly that other known or later-developed technologies for processing the plant derived organic source material to produce sugar, may be utilized in conformity with the present invention.

Fermentation

Fermentation of the organic material yields a fermentation based fuel and biogenic carbon dioxide. The fermentation based fuel includes any product or byproduct of the fermentation used as a fuel or as a fuel intermediate. A fuel intermediate is a precursor used to produce a fuel by a further conversion process, such as by fermentation or chemical reaction. The fermentation based fuel may be a liquid fuel or fuel intermediate, such as an alcohol, or a gaseous fuel or fuel intermediate produced by fermentation, such as biomethane.

Non-limiting examples of liquid fuels or fuel intermediates that can be used in accordance with the invention include alcohols such as ethanol, propanol, butanol and isobutanol. Most preferably, the alcohol is ethanol. Also preferred is ethanol that is not made from corn starch, but other plant derived organic material. The gaseous fuel or fuel intermediate may be produced by anaerobic digestion, as set out below. Hydrogen may also be produced from organic material in accordance with the invention. The fuel includes, but is not limited to, transportation fuel or heating fuel. The fuel may be for use in motor vehicles, motor vehicle engines, non-road vehicles or non-road engines, jets and for heating applications.

The fermentation utilized to generate the biogenic carbon dioxide of the present invention can be conducted using any suitable biocatalyst, including fermentation microorganisms selected from yeast, fungi and bacteria. The organic material that serves as the carbon and/or energy source for the fermentation may be plant derived or derived from animals, such as animal waste products, as set forth above.

The fermentation may be conducted in batch, continuous or fed-batch modes with or without agitation. Preferably, the fermentation reactors are agitated lightly with mechanical agitation. A typical commercial-scale fermentation may be conducted using multiple reactors. The fermentation microorganisms may be recycled back to the fermentor or may be sent to downstream processes without recycle.

Although the process conditions can vary, in one embodiment of the method of the present invention, the fermentation is performed at or near the temperature and pH optimum of the fermentation microorganism. Without being limiting, a typical temperature range for yeast fermenting glucose is between about 25° C. and about 35° C.; however, the temperature may be higher if the yeast is naturally or genetically modified to be thermostable. For anaerobic digestion, a typical temperature range is often higher, such as between about 50° C. and about 70° C. The amount of the fermentation microorganism used to inoculate the fermentation may depend on factors such as the activity of the fermentation microorganism, the desired fermentation time, the volume of the reactor and other parameters. It will be appreciated that these parameters may be adjusted to achieve the desired fermentation conditions.

The fermentation may also be supplemented with additional nutrients required for the growth of the fermentation microorganism. For example, yeast extract, specific amino acids, phosphate, nitrogen sources, salts, trace elements and vitamins may be added to the fermentation to support their growth.

The fermentation organism or biocatalyst used may depend on the substrate and the fermentation based fuel that is produced. For ethanol production, the fermentation may be carried out with any microorganism suitable for such purpose, including yeast and bacteria. Saccharomyces spp. yeast is a typical biocatalyst for ethanol production, although other biocatalysts may be used to produce the fermentation based fuel. Ethanol production can also be carried out with bacteria such as Escherichia coli, Klebsiella oxytoca and Zymomonas mobilis. Butanol may be produced from glucose by a microorganism such as a bacterium, including Escherichia coli or Clostridium acetobutylicum. Propanol production can be carried out using bacteria, such as Escherichia coli. Isobutanol can be produced fermentatively by yeast, including those described in WO 2010/075504.

The product of the fermentation can be used as a fuel itself. Alternatively, the product of the fermentation can be utilized as a fuel intermediate. For example, processes are known for converting isobutanol produced fermentatively to fuels, including hydrocarbon fuels such as jet fuel, diesel and gasoline.

The fermentation may be an anaerobic digestion, which is the biologic breakdown of organic material by microorganisms under low oxygen conditions, or in the absence of oxygen, to produce gases. The gases produced by anaerobic digestion of organic material include biogenic carbon dioxide and “biogas” comprising biomethane, also referred to herein as biogas derived methane or renewable natural gas. Other gases may be generated during anaerobic digestion as well, such as hydrogen. As would be appreciated by those skilled in the art, anaerobic digestion generally involves the decomposition of waste organic material, including carbohydrates, fats and proteins therein, into simple sugars and glycerol. These compounds are then converted to acids, which are then converted into biomethane by methanogenic bacteria or other microorganisms. Biomethane can be used as a fuel itself or used to produce other fuels, as described in co-pending U.S. provisional application No. 61/579,517, which is incorporated herein by reference in its entirety.

The biogas may be produced at a municipal or industrial operation. This includes, without limitation, a landfill, a waste treatment facility, such as a sewage treatment facility, and a manure digestion facility, such as a facility located on a farm or a facility that processes materials collected from farms. The digestion may or may not be contained within an anaerobic digester.

The biogas and biogenic carbon dioxide is optionally derived from landfill waste. Landfill biogas may be produced by organic material decomposing under anaerobic conditions in a landfill. The waste is covered and mechanically compressed by the weight of the material that is deposited from above. This material prevents oxygen exposure thus allowing anaerobic microbes to thrive. By appropriately engineering a collection system at the landfill site, the resultant biogas and biogenic carbon dioxide is captured. Biogas and biogenic carbon dioxide can also be produced from organic material that is separated from waste that otherwise goes to landfills. According to further embodiments of the invention, the biogas production site contains an anaerobic digester for digesting the waste.

Collection of Biogenic Carbon Dioxide

In accordance with the present invention, after production the biogenic carbon dioxide is collected for later use. Collection of biogenic carbon dioxide from a fuel fermentation can be conducted in any manner sufficient to ensure that a desired level of carbon dioxide evolved or generated from the fermentation is recovered. The difference between the amount of carbon dioxide produced from the fermentation and the amount of carbon dioxide recovered, by weight, represents the amount of carbon dioxide collected and is measured by standard techniques. The amount of carbon dioxide collected from the fermentation may be greater than about 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85, 90, 95, or 98 wt % of the biogenic carbon dioxide generated during the fermentation. According to certain embodiments of the invention, between 5 and 85 wt %, or between 15 and 80 wt % of the biogenic carbon dioxide generated during fermentation is collected. In further embodiments of the invention, between 5 and 90 wt % or between 30 and 90 wt % of the biogenic carbon dioxide generated during the fermentation is collected. Preferably, during collection, the biogenic carbon dioxide is purified and compressed. The purification may remove water, air, the fuel or fuel intermediate or optionally other impurities.

(a) Collection of Biogenic Carbon Dioxide from Liquid Fuel Fermentation

Known techniques for collecting carbon dioxide from fermentations that produce liquid fuels or fuel intermediates that can be used in the practice of the invention include systems that comprise a water scrubbing unit in which water is flowed counter-current to the carbon dioxide to remove water and water soluble components, including ethanol. Water that remains in the carbon dioxide is subsequently removed in a compressor to increase the pressure of the carbon dioxide up to the water condensation level. The carbon dioxide may be fed to a drying unit to remove additional water. A purifying unit, which typically contains activated carbon, may be included in the process configuration before or after the drying unit to remove impurities. Inert gases, such as oxygen and nitrogen (also referred to in the art as non-condensable or permanent gases), may subsequently be removed in a condenser.

Although recovery of inert gases in a condenser is described, other methods can be used to remove the inert gases, and may result in improvements in recovery levels. Without being limiting, inert gases may be removed by a rectification column. A further technique for recovering high levels of carbon dioxide generated during fermentation that can be used in the practice of the invention is cold condensing to remove non-condensable gases, which relies on low temperature to decrease the solubility of the non-condensable gases so that they volatilize from the liquid phase. Cold condensing may be conducted after drying or purification.

It will be understood, however, that the invention is not restricted in scope to the methods described above and encompasses alternative procedures, including later-developed technologies, for collecting biogenic carbon dioxide from liquid fuel fermentations.

(b) Separation and Collection of Biogenic Carbon Dioxide from Biogas

As set forth previously, anaerobic digestion produces biogenic carbon dioxide and biogas comprising methane, also referred to as biogas derived methane, biomethane or renewable natural gas. Biogenic carbon dioxide mixed with biogas and optionally any other substances produced during anaerobic digestion may be separated from the biomethane by known or later-developed techniques. For example, such separation may comprise scrubbing, including water or solvent scrubbing, such as polyethylene glycol scrubbing. Scrubbing involves flowing biogas through a column with a water or solvent solution flowing counter-current to the biogas. Biogenic carbon dioxide is separated from the biomethane by these techniques since carbon dioxide and other components are more soluble in water or the solvent than biomethane.

A further technique for separating biogenic carbon dioxide from the biomethane is pressure swing absorption, which utilizes adsorptive materials, such as zeolites and activated carbon that preferentially adsorb carbon dioxide at high pressure. When the pressure is released, the biogenic carbon dioxide desorbs.

It will be understood, however, that the invention is not restricted in scope to the methods described above and encompasses alternative procedures, including later-developed technologies, for separating biogenic carbon dioxide from biomethane.

Transportation and Use of Biogenic Carbon Dioxide in an Enhanced Oil or Gas Recovery Operation to Displace Geologic Carbon Dioxide

After collection, the biogenic carbon dioxide can be introduced to an apparatus for transporting the biogenic carbon dioxide to one or more sites that inject carbon dioxide to facilitate enhanced oil or gas recovery. The apparatus may include a pipeline or other transportation means as discussed further below.

The enhanced oil recovery is any process that enables the recovery of underground oil with the aid of fluid, including liquid or gas injection or two-phase fluid, such as foam. Preferably, liquid injection is employed. The enhanced oil recovery may include the use of cyclic or continuous steam, water flooding, steam flooding or fire flooding. Optionally, the enhanced oil recovery operation also employs microbial injection or thermal recovery in combination with fluid injection. An enhanced oil recovery site refers to one or multiple wells in an oil field that are configured in such a way that carbon dioxide is injected underground so that the carbon dioxide contacts the underground oil to aid or facilitate the recovery of oil or crude petroleum. The enhanced oil recovery site may comprise two or more wells comprising at least one injection well and at least one production well, although it is possible to use one well.

The enhanced gas recovery is any process that enables the recovery of underground natural gas with the aid of fluid, including liquid, gas or two-phase fluid, such as foam. The enhanced gas recovery operation includes any process that involves the introduction of fluid to an underground gas-bearing formation to aid or facilitate the recovery of natural gas. The enhanced gas recovery may be a hydraulic fracturing process using carbon dioxide to recover underground natural gas, as discussed below.

An enhanced gas recovery site refers to one or multiple wells that are configured in such a way that carbon dioxide is injected underground to aid or facilitate the recovery of natural gas. The natural gas may be recovered from any underground source containing natural gas, including coal formations, shale gas formations, tight sands formations, such as sandstone or limestone formations, hydrated natural gas deposits, methane clathrate deposits or depleted natural gas fields. In the case of coal or shale gas deposits, the natural gas may be adsorbed in pores of the coal or shale.

As noted above, the enhanced oil or gas recovery of the invention may be a hydraulic fracturing process to recover underground oil or natural gas. Hydraulic fracturing initiates and/or expands underground fractures, cracks and/or fissures by the introduction of a pressurized fluid, also known as a “fracturing fluid”. The formation of such fractures, cracks and/or fissures frees oil or gas present in a rock or other tight formation, thereby allowing it to flow and ultimately be recovered. As would be appreciated by those of skill in the art, granular substances may also be introduced underground along with the fracturing fluid. Such substances, referred to in the art as “proppants”, function to prevent the fractures, cracks and/or fissures from closing after they are formed. Other additives such as surfactants, gelling agents, foaming agents, acids and gases, such as nitrogen, can optionally be included in the fracturing fluid along with carbon dioxide. Without being limiting, a hydraulic fracturing site may include at least one well that is drilled vertically for a certain distance and then extends horizontally or substantially horizontally into a gas-bearing or oil-bearing formation.

The inclusion of carbon dioxide in the fracturing fluid can provide numerous benefits during gas or oil recovery. Without being limiting, the amount of oil or gas recovered during a hydraulic fracturing process may be increased through the use of carbon dioxide. The mechanism by which carbon dioxide enhances oil or gas recovery during hydraulic fracturing will generally depend on the particular application. The carbon dioxide introduced during hydraulic fracturing may displace natural gas that is present in a gas-bearing formation. For example, the carbon dioxide may displace natural gas that is adsorbed onto coal or shale as it has a higher affinity for the shale or coal than natural gas. The result is that natural gas is released from the gas shale or coal and ultimately recovered, while carbon dioxide is adsorbed and remains underground. Carbon dioxide can also function to pressurize a formation, which aids in the recovery of underground oil or gas.

The carbon dioxide can also be introduced to the underground oil or gas containing formation in the form of a foam. The use of carbon dioxide as a foam during hydraulic fracturing, also referred to as “foam fracturing”, can reduce water usage in the fracturing process. Among other advantages, carbon dioxide reduces swelling in clay sensitive formations, lowers the pH of the fracturing fluid and can aid in removing any blocks in the formation. The carbon dioxide may be used as a carrier for proppant or another fluid may be used for this purpose.

The fluid used in a hydraulic fracturing process may be solely or predominantly carbon dioxide, or carbon dioxide may be included as an additive to the fracturing fluid that is introduced underground. For example, the amount of carbon dioxide in the fracturing liquid may be greater than 10, 20, 30, 40, 50, 60, 70, 80 or 90% by weight.

The carbon dioxide for use in the foregoing enhanced oil recovery or enhanced gas recovery may be transported across land or sea by an apparatus adapted for such purpose. According to certain embodiments, the apparatus for transporting carbon dioxide is a pipeline, a container for transporting the biogenic carbon dioxide by rail, trucking, shipping, barge, or any other commercial distribution system. It should be appreciated that the biogenic carbon dioxide could be placed in the apparatus for storage prior to transportation. Furthermore, the apparatus for transporting carbon dioxide to the enhanced oil or gas recovery operation can be either integral with or unconnected to an apparatus used to collect biogenic carbon dioxide. The biogenic carbon dioxide may be transported in gaseous or liquid form. Preferably, the biogenic carbon dioxide is transported in liquid form or supercritical fluid.

In a preferred embodiment, the apparatus is a pipeline, including a carbon dioxide dedicated pipeline and commercial distribution pipeline or fungible carbon dioxide pipeline. The pipeline may feed one or multiple enhanced oil or gas recovery sites that inject carbon dioxide to facilitate enhanced oil or gas recovery. Furthermore, plural carbon dioxide sources, including potentially anthropogenic or geologic carbon dioxide, may feed into the pipeline. It should be appreciated that when using a fungible carbon dioxide pipeline to supply the enhanced oil or gas recovery site(s) or operation(s), beneficial environmental impacts associated with biogenic carbon dioxide can be realized by end users under regulations and/or through contracts or the like. Thus, the withdrawal of non-biogenic carbon dioxide from the pipeline which delivers carbon dioxide to the enhanced oil or gas recovery site may be used to qualify for life cycle GHG reductions.

In another embodiment of the invention, a fuel production facility arranges for, or causes, a third party to supply biogenic carbon dioxide for use in an enhanced oil or gas recovery operation. The term “fuel production facility” or “biofuel production facility” refers to any facility that produces a fuel or fuel intermediate by fermentation. By the terms “arranging” or “causing”, it is meant to bring about, either directly or indirectly, including through commercial arrangements such as a written agreement, verbal agreement or contract. Without being limiting, the third party may be an intermediary that obtains biogenic carbon dioxide from a fuel production facility and supplies it to an enhanced oil or gas recovery operation.

When the biogenic carbon dioxide is delivered to the enhanced oil or gas recovery site, it is introduced into an underground oil-bearing or gas-bearing formation, typically through injection via an injection well. As would be appreciated by those of skill in the art, in the case of enhanced oil recovery, carbon dioxide injection may alternate with water and/or brine injection. The introduction of carbon dioxide in enhanced oil or gas recovery increases the mobility of the oil or gas so that it can be withdrawn by one or more wells, typically referred to as production wells. The oil or gas that enters the production well(s) rises or is pumped to the surface. As would be appreciated by those of skill in the art, the carbon dioxide may rise or be pumped to the surface along with the recovered oil and then recovered and re-introduced back underground. With respect to either enhanced oil or gas recovery, the site may include at least one well that is drilled vertically for a certain distance and then extends horizontally or substantially horizontally into an oil- or gas-bearing formation. It should be understood that the enhanced oil or gas recovery may be conducted using any known or later developed technologies to recover oil or gas.

Displacement of geologic carbon dioxide with biogenic carbon dioxide means that less geologic carbon dioxide is used in or supplied to an enhanced oil or gas recovery operation or site than would otherwise be the case with an alternative geologic supply, as a result of the use or supply to such operation or site of biogenic carbon dioxide collected from a fermentation, including a liquid fuel fermentation or anaerobic digestion. In one embodiment, displacement refers to a reduction in the use of geologic carbon dioxide at one or more enhanced oil or gas recovery sites that is otherwise available for use at one or more enhanced oil or gas recovery sites, wherein the reduction in use of geologic carbon dioxide results from (i) introducing biogenic carbon dioxide into an apparatus for transporting the biogenic carbon dioxide to one or more enhanced oil or gas recovery sites; (ii) taking geologic carbon dioxide out of use at one or more enhanced oil or gas recovery sites and using biogenic carbon dioxide at the enhanced oil or gas recovery site; or both (i) and (ii). In a further embodiment of the invention, displacement results from the introduction of biogenic carbon dioxide into an apparatus for transporting carbon dioxide to one or more enhanced oil or gas recovery sites that used or are using geologic carbon dioxide. In yet further embodiments of the invention, displacement results from the supply of biogenic carbon dioxide for use in one or more enhanced oil or gas recovery sites that used or are using geologic carbon dioxide. Beneficially, this reduces life cycle GHG emissions of the fuel or fuel intermediate made from the fermentation process in which the biogenic carbon dioxide was produced. In yet further embodiments, demand for geologic carbon dioxide is reduced due to the supply of biogenic carbon dioxide to one or more enhanced oil or gas recovery sites where this reduced demand qualifies for reducing life cycle GHG emissions. In one such embodiment, displacement results from a reduction in demand for geologic carbon dioxide that is otherwise available for use at one or more enhanced oil or gas recovery sites, wherein the reduction in demand of geologic carbon dioxide results from (i) introducing biogenic carbon dioxide into an apparatus for transporting carbon dioxide to one or more enhanced oil or gas recovery sites; or (ii) taking geologic carbon dioxide out of use at one or more enhanced oil or gas recovery sites and using biogenic carbon dioxide at the enhanced oil or gas recovery site.

The use of biogenic carbon dioxide to displace geologic carbon dioxide includes supplying biogenic carbon dioxide for use, for example by another party, in replacing, substituting or using biogenic carbon dioxide as a priority over geologic carbon dioxide that could otherwise be used at the site. Preferably, the biogenic carbon dioxide supplied for use in an enhanced oil or gas recovery operation displaces a corresponding amount of geologic carbon dioxide used in the enhanced oil or gas recovery operation or one or more sites. This may involve taking out of use a first amount of geologic carbon dioxide at one or more enhanced oil or gas recovery sites or operation and supplying, preferably subsequently supplying, an amount of biogenic carbon dioxide at one or more enhanced oil or gas recovery sites or operation to displace the first amount of geologic carbon dioxide. The biogenic carbon dioxide may displace all of the geologic carbon dioxide used in the enhanced oil or gas recovery operation or a portion of geologic carbon dioxide used in the enhanced oil or gas recovery operation.

By way of example, if 10 units of biogenic carbon dioxide are introduced to a pipeline and 10 units of carbon dioxide are withdrawn from the pipeline with the GHG emission attributes of the input biogenic carbon dioxide and used in an enhanced oil or gas recovery site, and 10 units of geologic carbon dioxide are taken out of use or removed from use at the enhanced oil or gas recovery site, then 10 units of geologic carbon dioxide have been displaced at the enhanced oil or gas recovery site. It should be understand that the biogenic carbon dioxide may displace only a portion of the geologic carbon dioxide used in the enhanced oil or gas recovery operation. For example, if the enhanced oil or gas recovery site previously used 100 units of geologic carbon dioxide and 10 units of the geologic carbon dioxide are displaced by 10 units of biogenic carbon dioxide, then only 90 units of geologic carbon dioxide need be used in the enhanced oil or gas recovery operation. Additionally, displacement may occur if biogenic carbon dioxide is used to increase the amount of carbon dioxide used at the enhanced oil or gas recovery site. For example, if the enhanced oil or gas recovery site previously used 100 units of geologic carbon dioxide and an additional 10 units of biogenic carbon dioxide are then used in enhanced oil or gas recovery, so that 110 units of carbon dioxide are used, then 10 units of geologic carbon dioxide can be considered displaced because the demand for an additional 10 units of geologic carbon dioxide has been obviated.

When the biogenic carbon dioxide is transported by pipeline, the amount of geologic carbon dioxide that is displaced by biogenic carbon dioxide may be measured by gas metering. For example, a meter would be placed in proximity to the facility in which biogenic carbon dioxide is produced to measure the amount of biogenic carbon dioxide supplied to the pipeline. Similarly, the amount of carbon dioxide withdrawn from the pipeline for supply to the enhanced oil or gas recovery site would be metered. Written documentation as described herein can set out the amounts of biogenic carbon dioxide introduced to the pipeline and withdrawn for use at the enhanced oil or gas recovery. Optionally, the producer of biogenic carbon dioxide would contract with the owner of the enhanced oil or gas recovery site, sites or operation to supply biogenic carbon dioxide. If the pipeline is supplied by multiple carbon dioxide sources, some of which are non-biogenic, the carbon dioxide withdrawn may be non-biogenic or contain a mixture of biogenic and non-biogenic carbon dioxide. Nonetheless, an amount of carbon dioxide equal to the input amount of biogenic carbon dioxide can be withdrawn and can qualify for life cycle GHG reductions, for the reasons discussed previously.

In one embodiment, the introduction of biogenic carbon dioxide into an apparatus for transporting carbon dioxide to one or more enhanced oil or gas recovery sites that used or are using geologic carbon dioxide reduces GHG emissions because the biogenic carbon dioxide performs the function previously carried out by geologic carbon dioxide. According to a preferred embodiment of the invention, such a displacement can be evidenced by written documentation that sets out a life cycle analysis of the fermentation based fuel and includes in the analysis a GHG emission reduction calculation due to a displacement of geologic carbon dioxide that could be used in the absence of the use of biogenic carbon dioxide in enhanced oil or gas recovery. Preferably, such written documentation is in computer readable format. In some embodiments, the GHG emission reductions occur even in situations where there is no immediate reduction in the use of geologic carbon dioxide. Notably, this concept is similar to indirect land use impacts on greenhouse gas emissions, which are commonly used in life cycle GHG emission analyses of biofuels. In the case of land use impacts, changes in emission are calculated using the lifetime emissions effects associated with forecast changes in long term land use.

With respect to the present invention, over the lifetime of a site or sites using geologic carbon dioxide, use of biogenic carbon dioxide leads to avoided use of geologic carbon dioxide even if there is no immediate reduction in the use of geologic carbon dioxide. By “lifetime of the site or sites”, it is meant the time period from which carbon dioxide is first injected into one or more well on an enhanced oil or gas recovery site up until the last injection occurs in a respective well prior to closure of the site. The oil or gas in such sites is finite, and the use of carbon dioxide generally continues until the extraction of the finite resource is no longer economic. Thus, over the lifetime of a site employing carbon dioxide, there is a finite amount of carbon dioxide that is used. When biogenic carbon dioxide is used at a site employing geologic carbon dioxide, because the total carbon dioxide use is finite, there is a reduced amount of total geologic carbon dioxide used. A displacement of geologic carbon dioxide by biogenic carbon dioxide occurs over the lifetime of a site or sites, and such displacement is considered to provide GHG emissions benefits over the lifetime of the site or sites, even if there is not an immediate reduction in the use of geologic carbon dioxide.

According to one embodiment of the invention, such GHG emission reductions are quantified in data and written documentation including, but not limited to, a letter, memorandum, affidavit, form or submission to governmental authorities or a contract that states, commits, guarantees or otherwise indicates that biogenic carbon dioxide is used to displace the use of geologic carbon dioxide. The written documentation may, for example, comprise documentation describing a life cycle GHG analysis which includes a quantification of a GHG emission reduction of the fuel or fuel intermediate due to a reduction in the use of geologic carbon dioxide that would occur over the lifetime of the site or sites as a result of the use of biogenic carbon dioxide. Written documentation and data evidencing such a displacement that reduces GHG emissions is typically supplied to, and meets the requirements of, government regulators, such as the EPA.

According to some embodiments of the present invention, in order to determine that the biogenic carbon dioxide is being used to displace geologic carbon dioxide, at least one or more enhanced oil or gas recovery sites meets at least two of the conditions selected from: (a) the site has used geologic carbon dioxide in its enhanced oil or gas recovery; (b) the site has access to geologic carbon dioxide for use in its enhanced oil or gas recovery; and (c) written documentation indicates that biogenic carbon dioxide is being used to displace geologic carbon dioxide.

Referring to condition (a), “used geologic carbon dioxide in its enhanced oil or gas recovery”, means that the site has injected geologic carbon dioxide underground in its enhanced oil or gas recovery operations at some time in its history, including but not limited to times prior to or after the start of its use of the biogenic carbon dioxide. It should be appreciated that the time span between use of geologic carbon dioxide and the subsequent use of the biogenic carbon dioxide can vary. That is, the geologic carbon dioxide can be taken out of use, and immediately followed by the use of biogenic carbon dioxide or the period of time between geologic and biogenic carbon dioxide use can span a longer period of time, for example, days, months or even years. Furthermore, it should be understood that there could be some intermixing of geologic, anthropogenic and biogenic carbon dioxide in the enhanced oil or gas recovery operations.

Access to geologic carbon dioxide refers to the ability to use geologic carbon dioxide at the site if biogenic carbon dioxide were not available. A site has access to geologic carbon dioxide if, for example, it is or was served by a pipeline that delivered geologic carbon dioxide. In some embodiments of the invention, an enhanced oil or gas recovery site has access to geologic carbon dioxide by being located within a 100 mile radius from the closest point on a carbon dioxide pipeline into which geologic carbon dioxide is fed, or within a 75, 50, 25 or 10 mile radius. According to a further embodiment, the carbon dioxide pipeline into which geologic carbon dioxide is fed is or was connected to the enhanced oil or gas recovery site; preferably, the pipeline is connected to the enhanced oil or gas recovery site.

As discussed, displacement in accordance with the invention may be evidenced by data and written documentation, which indicates that biogenic carbon dioxide is being used to displace geologic carbon dioxide at the site, as set out below. To attain credit for life cycle carbon dioxide emissions reductions, written documentation is generated which contains a life cycle GHG analysis of the fermentation fuel or fuel intermediate that includes displacement of geologic carbon dioxide as contributing in whole or in part to life cycle GHG reduction. Such documentation is typically supplied to a government regulatory authority.

By “written documentation indicates that biogenic carbon dioxide is being used to displace geologic carbon dioxide” at the site, it is meant that a written document including, but not limited to, a letter, memorandum, affidavit, form or submission to governmental authorities or a contract states, commits, guarantees or otherwise indicates that biogenic carbon dioxide is used to displace, replace, substitute for or otherwise reduce the use of geologic carbon dioxide. The written documentation may comprise documentation describing life cycle GHG analysis indicating that the use or supply of biogenic carbon dioxide for displacement of geologic carbon dioxide creates a net GHG benefit.

In another embodiment, there is provided a method that comprises fermenting organic material to produce a fermentation based fuel, or fuel intermediate, such as an alcohol, collecting at least 5 wt % of the biogenic carbon dioxide that is produced in the fermentation, introducing all or a portion of the biogenic carbon dioxide into apparatus for transporting the biogenic carbon dioxide to one or more enhanced oil or gas recovery sites, wherein, in respect to one or more of the sites, written documentation indicates that the use of biogenic carbon dioxide to displace geologic carbon dioxide is included in a net life cycle carbon dioxide emissions analysis. This life cycle carbon dioxide emissions analysis includes a carbon dioxide emissions savings due in whole or in part from the supply of biogenic carbon dioxide.

In a further embodiment, there is provided a method that comprises: fermenting the organic material to produce a fuel or fuel intermediate and biogenic carbon dioxide; collecting an amount of biogenic carbon dioxide, for example at least 5 wt % of the biogenic carbon dioxide generated from the step of fermenting; introducing the biogenic carbon dioxide into apparatus for transporting said biogenic carbon dioxide to one or more enhanced oil or gas recovery sites, wherein at least one of the sites meets one of the following conditions: (a) the site has used geologic carbon dioxide in its enhanced oil or gas recovery; and (b) the site has access to geologic carbon dioxide for use in its enhanced oil or gas recovery; and supplying the biogenic carbon dioxide for use in one or more enhanced oil or gas recovery sites to displace geologic carbon dioxide, as evidenced by written documentation. The written documentation indicates that biogenic carbon dioxide is being used to displace geologic carbon dioxide at the site, as set out above.

Additional methods can be employed in combination with displacing geologic carbon dioxide with biogenic carbon dioxide to reduce the overall GHG life cycle emissions of the fuel or fuel intermediate. Such methods include, without limitation, increasing energy efficiency, energy saving and fuel switching. For example, the energy efficiency of a fermentation fuel production facility can be improved by, for example, increasing the number of stages of evaporation and distillation, employing heat recovery on dryers or using combined heat and power generation. Energy requirements can be lessened by reducing or eliminating energy consuming operations such as the drying of distillers grains. Fuel switching can reduce life cycle emissions by, for example, replacing natural gas, a fossil fuel, with biogas, a renewable fuel. Thus, even if a relatively small amount of the biogenic carbon dioxide generated in the fermentation is collected and supplied to one or more enhanced oil or gas recovery site for displacement of geologic carbon dioxide, the life cycle GHG emission reduction of the fuel or fuel intermediate relative to the gasoline baseline may still meet the threshold to generate a desired fuel credit if one or more of these additional methods are employed in combination with the invention. For example, if the life cycle GHG emissions of a fuel or fuel intermediate are reduced by one or more other methods, a life cycle GHG emission reduction of 50% relative to a gasoline baseline for a particular fuel or fuel intermediate could still be achieved if 5 wt % of the carbon dioxide produced from a fermentation is collected and used to displace geologic carbon dioxide at an enhanced oil or gas recovery site.

Use of the Fuel or Fuel Intermediate

The fermentation based fuel of the invention can be used as a transportation fuel. For example, ethanol may be blended with gasoline at levels from 5% to 85% ethanol and used to power motor vehicles. Ethanol is typically concentrated by distillation and an azeotropic breaking process prior to blending with gasoline. Ethanol can alternatively be used as a feedstock for making a transportation fuel component such as ethyl tert-butyl ether. Biogas derived methane may be used directly to power vehicles, or used as a feedstock to make transportation fuel, for example as disclosed in co-pending U.S. Application No. 61/579,517.

Alternatively, the fermentation based fuel can be used as an energy source for heating or to produce electricity. For example, biomethane or methane having reduced GHG emissions due to implementation of the invention can be used to supply energy to a fuel production facility, which includes any operation that produces a fuel or fuel intermediate from organic material, such as a liquid fuel production facility, including an ethanol production facility. The methane can also supply energy to any equipment used to support a fuel production process in a fuel production facility, referred to herein as “associated utilities”. The methane in this embodiment is biogas derived methane (also referred to as biomethane), including methane that qualifies under applicable laws or regulations as being renewably derived, as set forth below. In one embodiment, such methane is used in any part of a fuel production facility or associated utilities to supply heat and/or electricity. The methane can be combusted to provide steam, which can be used to drive turbines to create electricity for plant needs and/or to supply thermal energy within the facility. The methane can also be used in a direct gas turbine to make electricity. Thermal energy can be used for on-site heating, as process heat or for cooling operations. Furthermore, if electricity is generated from the methane, heat that is produced as a by-product during the electricity generation can often be used in the facility.

It should be appreciated that some of the methane used to supply energy to a fuel production facility or associated utilities can be natural gas. In other words, the energy need not be supplied exclusively by biomethane, but can be a combination of both natural gas and biomethane.

Biomethane can be transported to the fuel production facility by any suitable apparatus for transporting methane to a fuel production facility. In a preferred embodiment, such apparatus will be a pipeline, such as a natural gas pipeline or a biogas dedicated pipeline. Alternatively, the apparatus may be a container for transporting the biomethane by rail, trucking or shipping, or any other commercial distribution system.

In a preferred embodiment, the biomethane will be transported via a pipeline. If the pipeline is fed by a plurality of methane sources, some of which are not sourced from biomethane, the methane withdrawn may not contain actual molecules from the original organic material from which the biomethane is derived, but rather the energy equivalent value of the biomethane. With respect to biomethane used for electricity generation in a facility, government authorities have recognized that it does not make any difference, in terms of the beneficial environmental attributes associated with the use of biomethane, whether the displacement of fossil fuel occurs in a fungible natural gas pipeline, or in a specific fuel production facility that draws methane from that pipeline. Thus, methane withdrawn from a pipeline that is fed by biomethane, as well as methane derived from sources besides biomethane, will still be considered biomethane or biogas derived methane. As would be appreciated by those of skill in the art, the amount of methane withdrawn from such a pipeline with the GHG emission attributes of biomethane and the amount of biomethane fed to the pipeline will typically be consistent. The amount of biomethane fed to the pipeline and the amount of methane withdrawn can be determined by gas metering.

The methane produced using the invention that is supplied to the fuel production facility to provide energy has reduced life cycle GHG emissions. The reduced life cycle GHG emissions are measured relative to the biomethane production process baseline. Biomethane or methane that has reduced life cycle GHG emissions relative to this production process baseline is also referred to herein as “enhanced GHG biomethane”. As set forth previously, a biomethane production process baseline refers to the life cycle GHG emissions associated with a biogas production process conducted under identical conditions except the biogenic carbon dioxide that is separated from the biomethane is released to the atmosphere. In some embodiments of the invention, the reduction in life cycle GHG emissions results in whole or in part from the practice of or arranging for the practice of the following process by one or more third parties: (i) anaerobically digesting organic material to produce biogas comprising biomethane and biogenic carbon dioxide; (ii) separating the biomethane and biogenic carbon dioxide; (iii) collecting an amount of the biogenic carbon dioxide generated from the step of separating; and (iv) supplying the biogenic carbon dioxide from step (iii) for use in one or more enhanced oil or gas recovery sites for displacement of geologic carbon dioxide.

By arranging for the practice of the foregoing process by one or more third parties, it is meant to bring about the process, either directly or indirectly, including through commercial arrangements such as a written agreement, verbal agreement or contract.

Advantageously, when a fuel production facility receives and uses such enhanced GHG biomethane, the life cycle GHG or carbon dioxide emissions of the liquid fuel or fuel intermediate produced in the facility can be reduced significantly relative to a gasoline baseline.

Thus, according to certain aspects of the invention, there is provided a method to reduce the life cycle GHG or carbon dioxide emissions associated with production of a liquid fuel or fuel intermediate, the method comprising: (i) producing sugar from plant derived organic material and converting the sugar to the liquid fuel or fuel intermediate in a fuel production facility; (ii) using methane to supply energy in any part of the fuel production facility or associated utilities, wherein the methane has associated with it life cycle GHG or carbon dioxide emissions that are reduced relative to a biomethane production process baseline due to or as a result of the practice of or arranging for the practice of the following process by one or more third parties: (a) the collection of biogenic carbon dioxide from biogas comprising biomethane; (b) the supply of biogenic carbon dioxide collected in step (a) to one or more enhanced oil or gas recovery sites; (c) the introduction of the biomethane into an apparatus for transporting to the fuel production facility; and (d) the withdrawal of methane from the apparatus to supply energy in any part of the fuel production facility or associated utilities.

In another embodiment, there is provided a method to reduce the life cycle GHG or carbon dioxide emissions associated with production of a liquid fuel or fuel intermediate, the method comprising: (i) producing sugar from plant derived organic material and converting the sugar to the liquid fuel or fuel intermediate in a fuel production facility; (ii) using methane to supply energy in any part of the fuel production facility or associated utilities, wherein the methane has associated with it life cycle GHG or carbon dioxide emissions that are reduced relative to a biomethane production process baseline where such reduction is due in whole or in part to the displacement of geologic carbon dioxide with biogenic carbon dioxide that originated from an anaerobic digestion that produces biogas comprising biomethane and biogenic carbon dioxide.

According to a further embodiment of the invention, an amount of biogenic carbon dioxide that is produced from the above-mentioned step of converting the sugar to the liquid fuel or fuel intermediate is collected and supplied for use in one or more enhanced oil or gas recovery sites for displacement of geological carbon dioxide. The GHG emission reductions from collecting carbon dioxide from the conversion and using it to displace geologic carbon dioxide in an enhanced oil or gas recovery, combined with those resulting from using the methane having reduced GHG emissions in the fuel production facility to generate energy, may reduce the overall life cycle GHG emissions of the fuel or fuel intermediate relative to the gasoline baseline to a level that meets the threshold to generate a desired fuel credit.

The method may further comprise generating a renewable fuel credit associated with the liquid fuel or fuel intermediate. In some embodiments of the invention, the fuel credit is a RIN or an LCFS credit. The foregoing method may allow the fuel or fuel intermediate produced by the facility to qualify for a RIN having higher market value or for the generation of more LCFS credits, or both. If a RIN is generated, it is preferably a D5 RIN or a D3 RIN.

Measuring Life Cycle GHG Emissions of Fermentation Based Fuel

As set forth previously, the present invention overcomes uncertainties about the current and future level of GHG emissions benefits that arise due to leakage of carbon dioxide during or after the enhanced oil or gas recovery operation when compared to the use of biogenic carbon dioxide in enhanced oil or gas recovery without displacement. By displacing geologic carbon dioxide with biogenic carbon dioxide, debits due to leakage of biogenic carbon dioxide, can be off-set by credits due to the amount of geologic carbon dioxide that did not enter the atmosphere as a result of leakage of carbon dioxide during or after enhanced oil or gas recovery operations. Thus, the overall net reduction in emissions is equal to the amount of biogenic carbon dioxide that is supplied to the enhanced oil or gas recovery site to be sequestered underground, without any deductions for emissions related to current or future leakage.

The amount of carbon dioxide savings for the fuel or fuel intermediate can be calculated using methods known in the art. As much as 36.12 g CO₂ eq/MJ of ethanol (38,145 g CO₂ eq/MMBTU) can be obtained from collecting and using 100 wt % of the carbon dioxide evolved in fermentation and using it in accordance with the invention. This assumes no residual losses of carbon dioxide in collection, purification and transportation.

The ultimate amount of reduction in life cycle carbon dioxide emissions will depend on the type of fuel, fuel intermediate or alcohol produced, which influences the stoichiometry of the fermentation reaction, the amount of carbon dioxide collected and also any carbon dioxide losses associated with the process, e.g., in collection, purification, compression and transport. Without being limiting, it has been reported that as much as 80 wt % of carbon dioxide evolved from ethanol fermentation can be recovered (Buchhauser U, Vrabec J, Faulstich M, Meyer-Pittroff R., 2008, CO₂ Recovery: Improved Performance with a Newly Developed System. MBAA Technical Quarterly, 45(1):84-89). By way of example, if 38,145 g CO₂ eq/MMBTU is evolved in fermentation and 80 wt % of the amount of carbon dioxide evolved in fermentation is collected from a sorghum ethanol process with GHG fluxes comparable to Table 7 (see Example 1(a)), then the life cycle GHG emissions change associated with displacement of the geologic carbon dioxide by the biogenic carbon dioxide will lead to a reduction in the life cycle GHG emissions associated with the production of ethanol of approximately 23,308 g CO₂ eq/MMBTU ethanol relative to a production process baseline, taking into account 7,207 g CO₂ eq/MMBTU emissions due to the collection, purification, compression and transport of biogenic carbon dioxide.

It should be understood that the present invention is not constrained by the foregoing example. The upper limit of carbon dioxide that is recovered and the losses due to collection, purification, compression and transport are merely exemplary and should not be construed to limit the current invention in any manner.

According to certain embodiments, the invention reduces the life cycle GHG emissions associated with the production of a fuel or fuel intermediate, by between about 1.0 CO₂ eq/MJ and about 50 CO₂ eq/MJ, or between about 1.0 g CO₂ eq/MJ and about 40 g CO₂ eq/MJ, or between about 1.0 g CO₂ eq/MJ and 30 g CO₂ eq/MJ, or between about 1.0 g CO₂ eq/MJ and 25 g CO₂ eq/MJ, or between about 2.0 g CO₂ eq/MJ and about 25 g CO₂ eq/MJ, or between about 5.0 g CO₂ eq/MJ and about 25 g CO₂ eq/MJ or between about 5.0 g CO₂ eq/MJ and about 22.5 g CO₂ eq/MJ relative to a production process baseline.

According to further embodiments, the fuel produced by the fermentation is ethanol and the invention reduces the carbon dioxide or life cycle GHG emissions associated with the production of the ethanol by between about 1.0 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ, or between about 2.0 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ, or between about 2.0 g CO₂ eq/MJ and about 25 g CO₂ eq/MJ, or between about 5.0 g CO₂ eq/MJ and about 25 g CO₂ eq/MJ or between about 10 g CO₂ eq/MJ and about 25 g CO₂ eq/MJ relative to a production process baseline.

According to other embodiments, the fuel produced by the fermentation is butanol and the invention reduces the life cycle GHG emissions associated with the production of the butanol by between about 1.0 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ, or between about 2 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ, or between about 2.0 g CO₂ eq/MJ and about 25 g CO₂ eq/MJ, or between about 5.0 g CO₂ eq/MJ and about 25 g CO₂ eq/MJ or between about 10 g CO₂ eq/MJ and about 25 g CO₂ eq/MJ relative to a production process baseline.

According to other embodiments, the fuel produced by the fermentation is biomethane and the invention reduces the life cycle GHG emissions associated with the production of the methane by between about 1.0 g CO₂ eq/MJ and about 50 g CO₂ eq/MJ, or between about 2.0 g CO₂ eq/MJ and about 45 g CO₂ eq/MJ, or between about 5.0 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ, or between about 5.0 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ, or between about 10 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ relative to a biomethane production process baseline.

According to further embodiments, the invention reduces the life cycle GHG emissions associated with the production of biomethane by at least 1.0, 2.0, 3.0, 4.0, 5.0, 6.0, 7.0, 8.0, 9.0, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19 or 20 g CO₂ eq/MJ relative to a biomethane production process baseline. According to other embodiments, the invention reduces the life cycle GHG emissions associated with the production of biomethane by up to 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, 36, 37, 38, 39, 40, 41, 42, 43, 44, 45, 46, 47, 48, 49 or 50 g CO₂ eq/MJ relative to a biomethane production process baseline.

Furthermore, any units of g CO₂ eq/MJ or CO₂/MJ provided herein can be converted to g CO₂ eq/MMBTU or CO₂/MMBTU by multiplying by a conversion factor or 1054.35. Similarly, any units of CO₂ eq/MMBTU or CO₂/MMBTU can be converted to CO₂ eq/MJ or CO₂/MJ by dividing by this conversion factor.

According to certain particularly advantageous embodiments, the present invention provides a method to reduce the life cycle GHG emissions associated with the production of a fermentation based fuel, including ethanol for use as a fuel or fuel intermediate, by approximately 9.0 g CO₂ eq/MJ (about 9,536 g CO₂ eq/MMBTU) or more relative to a production process baseline based upon the capture of approximately 25 wt % or more of the amount of biogenic carbon dioxide evolved in fermentation. Preferably, the reduction in life cycle GHG emissions is greater than 20 g CO₂ eq/MJ (about 21,100 g CO₂ eq/MMBTU) relative to a production process baseline, and wherein at least approximately 55 wt % or more of biogenic carbon dioxide evolved in fermentation is captured and the fermentation based fuel is an alcohol that is ethanol, butanol or other isomer of butanol such as isobutanol.

According to further embodiments of the invention, the present invention provides a method to reduce the life cycle GHG emissions associated with the production of a fermentation based fuel, including alcohol used as a fuel or fuel intermediate, in which the amount of biogenic carbon dioxide used in an enhanced oil or gas recovery operation leads or contributes to an overall life cycle GHG emissions level that is less than 50% that of a gasoline baseline. Preferably, the fermentation based fuel is an alcohol, such as ethanol produced by the fermentation of wheat or sorghum, or butanol, including butanol isomers, such as isobutanol, produced from corn starch. In such an embodiment, the ethanol or butanol so produced would qualify for generation of a D5 RIN, as discussed hereinafter.

To determine life cycle GHG emissions associated with the fermentation based fuel or alcohol of the present invention, analyses are conducted to calculate the GHG emissions related to the production and use of the fermentation based fuel or alcohol throughout its life cycle. Life cycle GHG emissions include the aggregate quantity of GHG emissions related to the full life cycle of the fermentation based fuel or alcohol, including all stages of fuel and feedstock production and distribution, from feedstock generation or extraction through the distribution and delivery and use of the finished fuel to the ultimate consumer. GHG emissions account for total net GHG emissions, both direct and indirect, associated with feedstock production and distribution, the fuel and fuel intermediate production and distribution and use.

Because many of the laws adopted differentiate the requirements for fuels based upon their net GHG emissions impacts, it is known to those skilled in the art that regulators have developed and/or adopted methods to analyze and characterize the expected net GHG emissions of fuel pathways. Thus, according to certain embodiments of the invention, life cycle GHG emissions are determined in accordance with prevailing rules and regulations.

Life cycle GHG emissions evaluations generally consider GHG emissions associated with each of:

-   (a) feedstock production and recovery, including the source of     carbon dioxide in the feedstock, direct impacts such as chemical     inputs, energy inputs, and emissions from the collection and     recovery operations, and indirect impacts such as the impact of land     use changes from incremental feedstock production; -   (b) feedstock transport, including feedstock production and recovery     GHG emissions from feedstock transport including energy inputs and     emissions from transport; -   (c) fuel production, including chemical and energy inputs, emissions     and byproducts from fuel production (including direct and indirect     impacts); and -   (d) transport and storage of the fuel prior to use as a transport or     heating fuel, including chemical and energy inputs and emissions     from transport and storage.

Examples of models to measure life cycle GHG emissions associated with the production of a fermentation based fuel, such as an alcohol, include, but are not limited to:

-   (i) GREET Model—GHGs, Regulated Emissions, and Energy Use in     Transportation, the spread-sheet analysis tool developed by Argonne     National Laboratories; -   (ii) FASOM Model—a partial equilibrium economic model of the U.S.     forest and agricultural sectors developed by Texas A&M University; -   (iii) FAPR1 International Model—a worldwide agricultural sector     economic model that was run by the Center for Agricultural and Rural     Development (“CARD”) at Iowa State University; -   (iv) GTAP Model—the Global Trade Analysis Project model, a     multi-region, multi-sector computable general equilibrium model that     estimates changes in world agricultural production as well as     multiple additional models; and -   (v) ISO (International Organization for Standardization) standards     for GHG emissions accounting and verification—provides guidance for     quantification, monitoring and reporting of activities intended to     cause greenhouse gas (GHG) emission reductions or removal     enhancements.

One benefit of the present invention is the ability to create co-product credits. Co-product credits can be assigned if a co-product is produced in a biofuel production facility. The co-product displaces equivalent products in the market produced from fossil fuel energy sources. This reduces GHG emissions because fossil fuel energy to produce the equivalent co-product by conventional methods is reduced. With respect to the invention, the biogenic carbon dioxide displaces the use of geologic carbon dioxide and this substitutes carbon dioxide of underground origin by carbon dioxide from atmospheric origin, thereby improving atmospheric carbon dioxide levels. Examples of methodologies for calculating GHG emissions, or carbon intensity, that take into account co-product credits are disclosed in Detailed California-Modified GREET Pathway for Corn Ethanol, California Environmental Protection Agency, Air Resources Board, Jan. 20, 2009, Version 2.0; Wang et al., 2011, Energy Policy 39:5726-5736; and White Paper, Issues Related to Accounting for Co-Product Credits in the California Low Carbon Fuel Standard, State of California, Air Resources Board, each of which is incorporated herein by reference.

The life cycle GHG emissions or carbon intensity of the fuel or fuel intermediate of the invention are measured in carbon dioxide equivalents (CO₂ eq). As would be understood by those of skill in the art, carbon dioxide equivalents are used to compare the emissions from various GHGs based upon their global warming potential (GWP), which is a conversion factor that varies depending on the gas. The carbon dioxide equivalent for a gas is derived by multiplying the amount of the gas by the associated GWP.

grams of CO₂eq=((grams of a gas)*(GWP of the gas))

The GWP conversion value used to determine g CO₂ eq will depend on applicable regulations for calculating life cycle GHG emissions reductions. The GWP under EISA is 1, 21 and 310, respectively, for carbon dioxide, methane and nitrous oxide as set forth in Renewable Fuel Standard Program (RFS2) Regulatory Impact Analysis, February 2010, United States Environmental Protection Agency, EPA-420-R-10-006, pg. 13, of which the entire contents are incorporated herein by reference. Under California's LCFS, the GWP is 1, 25 and 298, respectively, for carbon dioxide, methane and nitrous oxide, as measured by the GREET model.

The unit of measure for carbon intensity or life cycle GHG emissions that may be used to quantify GHG emissions of the fuel or fuel intermediate of the present invention is grams CO₂ eq per MJ of energy in the fuel or grams CO₂ eq per million British thermal units of energy in the fuel (MMBTU). The units used to measure life cycle GHG emissions will generally depend on applicable regulations. For example, under the EPA regulations, GHG emissions are measured in units of grams CO₂ eq per million BTUs (MMBTU) of energy in the fuel. Under LCFS, GHG emissions are measured in units of grams CO₂ eq per MJ of energy in the fuel and are referred to as carbon intensity or CI. The life cycle GHG emissions of the renewable fuel are compared to the life cycle GHG emissions for gasoline, referred to as a gasoline baseline. GHG life cycle emissions are compared by reference to the use of gasoline per unit of fuel energy. The value of the gasoline baseline used in life cycle GHG emission calculations can depend on the regulatory body. The EPA measures the carbon intensity of gasoline (gasoline baseline) as 98,204 g CO₂ eq/MMBTU or 93.10 g CO₂ eq/MJ. Under California's LCFS, the gasoline baseline is 95.86 g CO₂ eq/MJ. Those of ordinary skill in the art can readily convert values herein from g CO₂ eq/MJ to g CO₂ eq/MMBTU or g CO₂ eq/MMBTU to g CO₂ eq/MJ by using an appropriate conversion factor. Further, it should be appreciated that the value for the gasoline baseline can change from time to time depending on prevailing regulations.

According to certain embodiments of the invention, the life cycle GHG emission reduction relative to a gasoline baseline is measured “using EPA methodology”, which means measuring life cycle GHG emissions reductions as disclosed in EPA-420-R-10-006 (supra), or supplanted by prevailing methodologies used by the EPA, which are publicly available.

According to a further embodiment of the invention, the life cycle GHG emission reduction relative to a gasoline baseline is measured using “LCFS methodology”, which means measuring life cycle GHG emissions reductions by California's LCFS methodology using the GREET model, as set forth in Detailed California-Modified GREET Pathway for Corn Ethanol, supra, or supplanted by prevailing methodologies used by regulators, which are publicly available.

According to one embodiment of the invention, the life cycle carbon dioxide emissions, rather than the life cycle GHG emissions, are determined for the fuel or fuel intermediate and compared to a gasoline baseline. For example, in those embodiments in which a reduction in carbon dioxide emissions relative to a production process baseline is quantified, a life cycle carbon dioxide emission reduction can be quantified instead of a life cycle GHG emission reduction.

Meeting Renewable and Low Carbon Fuel Targets

Advantageously, in view of the life cycle GHG savings that are achievable by the present invention, the fuel or fuel intermediate of the invention can qualify for a renewable fuel credit that has higher market value than other renewable fuel credits associated with lower life cycle GHG savings thresholds. For example, the fuel or fuel intermediate of the invention may have a life cycle GHG emission reduction of 50% or more relative to a gasoline baseline, and thus could qualify for a RIN under EISA having a D code of 5, which is an advanced biofuel under current regulations. A RIN having a D code of 5 has a higher market value than other RINs, such as a RIN having a D code of 6 requiring only a life cycle GHG emission reduction of 20% relative to a gasoline baseline under current regulations. Likewise, under the LCFS, fuels with greater reductions in life cycle GHG emissions qualify for a greater number of credits having higher market value than fuels with lower reductions. According to some embodiments of the invention, the fuel qualifies for both higher market value RINs and a greater number of credits under LCFS.

The credit may be generated by a fuel production facility or any other party in possession of the fermentation based fuel or fuel intermediate. This may include an intermediary party that provides the fermentation based fuel to a fuel blender or importer, or the fuel blender or importer themselves. According to certain embodiments of the invention, the credit or renewable fuel credit is caused to be generated by another party. According to such embodiments, a producer of the fermentation based fuel or fuel intermediate may cause an intermediary or other party, including a fuel blender or importer, to generate a credit.

Energy policy, including EISA and LCFS, and the generation of renewable fuel credits under each of these legislative frameworks, is discussed in turn below.

(i) Meeting Renewable Fuel Targets Under EISA

U.S. policymakers have introduced a combination of policies to support the production and consumption of biofuels and one important element of U.S. biofuel policy is the RFS. The RFS originated with the Energy Policy Act of 2005 (known as RFS1) and was expanded and extended by the EISA of 2007. The RFS expanded and extended under EISA is sometimes referred to as RFS2 or RFS as used herein.

Under the EISA, the RFS sets annual mandates for renewable fuels sold or introduced into commerce in the United States. The RFS sets mandates through 2022 for different categories of biofuels (see Table 3 below). There is an annually increasing schedule for minimum aggregate use of total renewable biofuel (comprised of conventional biofuels and advanced biofuels), total advanced biofuel (comprised of cellulosic biofuels, biomass-based diesel, and other advanced biofuels), cellulosic biofuel and bio-based diesel. The RFS mandates are prorated down to “obligated parties”, including individual gasoline and diesel producers and/or importers, based on their annual production and/or imports.

Each year, obligated parties are required to meet their prorated share of the RFS mandates by accumulating credits known as RINs, either through blending designated quantities of different categories of biofuels, or by purchasing from others the RINs of the required biofuel categories.

The RIN system was created by the EPA to facilitate compliance with the RFS. Credits called RINs are used as a currency for credit trading and compliance. RINs are generated by producers and importers of renewable biofuels and assigned to the volumes of renewable biofuels transferred into the fuel pool. RINs are transferred with the renewable fuel through the distribution system until they are separated from the fuel by parties who are entitled to make such separation (generally refiners, importers, or parties that blend renewable fuels into finished fuels). After separation, RINs may be used for RFS compliance, held for future compliance, or traded. There is a centralized trading system administered by the U.S. EPA to manage the recording and transfer of all RINs.

As would be appreciated by those of skill in the art, a RIN generated up to Jul. 1, 2010 was a 38 character numeric code that corresponded to a volume of renewable fuel produced in or imported into the United States. According to certain embodiments of the invention, a RIN may be characterized as numerical information. The RIN numbering system was in the format KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE where numbers are used to designate a code representing whether the RIN is separated from or attached to a specific volume (K), the calendar year of production or import (YYYY), Company ID (CCCC), Facility ID (FFFFF), Batch Number (BBBBB), a code for fuel equivalence value of the fuel (RR), a code for the renewable fuel category (D), the start of the RIN block (SSSSSSSS) and the end of the RIN block (EEEEEEEE). It should be appreciated that the information required for RIN generation and/or the format of the information may change depending on prevailing regulations. Under current regulations, a RIN contains many of the foregoing information and other information in the form of data elements that are introduced into a web-based system administered by the EPA known as the EPA Moderated Transaction System, or “EMTS”.

The D code of a RIN specifies the fuel type, feedstock and production process requirements and thus in certain embodiments of the invention the D code may be used to characterize the type of RIN, as set out hereinafter. The D code of a RIN is assigned a value between 3 and 7 under current regulations. The value assigned depends on the fuel type, feedstock and production process requirements as set out in Table 1 to 40 C.F.R. §80.1426. Examples of fuels assigned a D code of 3-7 under current regulations are provided below. These examples are for illustration purposes only and are not to be considered limiting to the invention.

TABLE 2 D code examples D code Fuel Type Example 3 Cellulosic biofuel Ethanol from cellulosic biomass from agricultural residues 4 Biomass-based diesel Biodiesel and renewable diesel from soy bean oil 5 Advanced biofuel Ethanol from sugarcane 6 Renewable fuel Ethanol from corn starch (conventional biofuel) 7 Cellulosic diesel Diesel from cellulosic biomass from agricultural residues

As set out previously, the RFS2 mandate volumes are set by four separate but nested category groups, namely renewable biofuel, advanced biofuel, cellulosic biofuel and biomass-based diesel. The requirements for each of the nested category groups are provided in Table 3.

The nested category groups are differentiated by the D code of a RIN. To qualify as a total advanced biofuel, the D code assigned to the fuel is 3, 4, 5 or 7, while to qualify as cellulosic biofuel the D code assigned to the fuel is 3 or 7 (Table 3).

According to current regulations, each of the four nested category groups requires a performance threshold in terms of GHG reduction for the fuel type. In order to qualify as a renewable biofuel, a fuel is required to meet a 20% life cycle GHG emission reduction (or be exempt from this requirement), while advanced biofuel and biomass-based diesel are required to meet a 50% life cycle GHG emission reduction and cellulosic biofuels are required meet a 60% life cycle GHG emission reduction, relative to a gasoline baseline. As well, each nested category group is subject to meeting certain feedstock criteria. As set out previously, the advanced biofuel nested category group excludes ethanol made from corn starch, which is only a renewable fuel.

TABLE 3 Nested category groups under RFS2 Life cycle GHG threshold Nested reduction category relative to group Fuel type gasoline baseline Renewable Conventional biofuels (D code 6) 20% biofuel and advanced biofuels (D code 3, 4, 5 or 7) Advanced Cellulosic biofuels (D code 3 or 50% biofuel 7), biomass-based diesel (D code 4 or 7), and other advanced biofuels (D code 5) Cellulosic Biofuel derived from 60% biofuels lignocellulosic material (D code 3) and bio-diesel derived lignocellulosic material (D code 7). Biomass- Conventional biodiesel (D code 4) 50% based or cellulosic diesel (D code 7) diesel

Advantageously, by displacing geologic carbon dioxide with biogenic carbon dioxide in one or more enhanced oil or gas recovery sites in accordance with the invention, and by using a feedstock that is not starch from corn, a fermentation fuel producer can produce a fuel or fuel intermediate having lower life cycle GHG emissions and in some embodiments can generate an advanced biofuel RIN associated with the fuel or fuel intermediate produced in their facility than could otherwise be generated. For example, a corn ethanol fuel producer that produces ethanol that only qualifies for a RIN having a D code of 6 can generate a RIN having a D code of 5 by switching to a non-corn starch feedstock, such as wheat or sorghum, and by using the biogenic carbon dioxide evolved during the ethanol fermentation to displace geologic carbon dioxide in enhanced oil or gas recovery. Such a fuel can meet the feedstock criteria and the aforesaid 50% GHG emission reduction threshold to qualify for an advanced biofuel, which in turn allows for the generation of a RIN having a D code of 5. Qualification of a fuel for a RIN having a D code of 5 is particularly advantageous as such RINs generally possess higher market value than those having a D code of 6, and thus can yield higher prices when traded with another party and/or sold to an obligated party. It should be appreciated that further measures in addition to that provided by the invention can be employed to meet the threshold GHG reductions to qualify for a desired RIN or more LCFS credits. Such measures may include, without limitation, reducing plant consumption by process changes or substituting energy sources at the plant to lower GHG intensive sources such as biogas or renewable electricity.

Thus, according to certain embodiments of the invention, a RIN credit containing information or a value corresponding to a reduction in life cycle GHG emissions relative to a baseline is generated with the production of a volume of the fermentation based fuel. The information may correspond to a reduction in life cycle GHG emissions of at least 40, 45, 50, 55, 60, 65, 70, 75, 80 or 85% relative to a gasoline baseline. As set out above, the invention may contribute wholly or in part to achieving reductions in the life cycle GHG emissions of the fuel or fuel intermediate relative to a gasoline baseline.

The RIN associated with the fermentation based fuel or fuel intermediate may be assigned a D code of 3, 4, 5 or 7, also referred to herein as a D3, D4, D5 and D7 RIN, respectively. According to certain embodiments, the RIN associated with the fermentation based fuel or fuel intermediate may be assigned a D code of 3 or 5. Under current regulations, this corresponds to cellulosic biofuel and advanced biofuel fuel types, which meet GHG emissions reductions of 60% and 50%, respectively, relative to a gasoline baseline. This excludes ethanol from corn starch, which under current regulations is assigned a D code of 6. Preferably, the RIN associated with the fermentation based fuel is assigned a D code of 5.

According to a further embodiment of the invention, the fermentation based fuel may qualify for a D code having a lower numerical value than could otherwise be achieved by not practicing the invention. For example, a fuel, including but not limited to fuel made from wheat or sorghum, may be assigned a D code of 5 instead of 6 by carrying out the displacement in accordance with the invention.

In alternative embodiments of the invention, corn starch may be used as a feedstock to produce the fermentation based fuel, with the proviso that the fermentation based fuel is not ethanol. According to such embodiments, other alcohols, such as butanol or isobutanol, may be produced from corn starch.

According to some embodiments of the invention, a RIN is characterized as containing numerical information associated with the fuel or fuel intermediate produced by the method of the invention. Thus, a party may generate RINs comprising numerical information relating to an amount of fuel or fuel intermediate representing at least three parameters selected from (i) the type of renewable fuel that the fuel or fuel intermediate is; (ii) the year in which the fuel or fuel intermediate was produced or the year the numerical information was produced; (iii) registration number associated with the producer or importer of the fuel or fuel intermediate; and (iv) serial number associated with a batch of the fuel or fuel intermediate. The numerical information may also include one or more of the following parameters selected from: (i′) a number identifying that the numerical information is assigned to a volume of fuel or fuel intermediate, or separated; (ii′) a registration number associated with the facility at which the fuel or fuel intermediate was produced or imported; (iii′) a number representing a value related to an equivalence value of the fuel or fuel intermediate; (iv′) a number representing a first-volume numerical information associated with a batch of the fuel or fuel intermediate; and (v′) a number representing a last-volume numerical information associated with a batch of the fuel or fuel intermediate.

The RIN or numerical information described herein or portion thereof is provided to a government regulatory agency, including the EPA, in connection with generating a RIN. In some embodiments of the invention, the numerical information is also provided to a purchaser of the fermentation based fuel or a fuel derived therefrom. The numerical information described herein or portions thereof may be stored electronically in computer readable format.

The purchaser of the fermentation based fuel, or a fuel derived therefrom, may separate the RIN. As set out above, separation of a RIN from a volume of the alcohol, or a fuel derived therefrom, means termination of the assignment of the RIN to a volume of fuel. RIN separation is typically carried out by a fuel blender, importer or other obligated party. According to pre-2010 regulations, when a RIN is separated, the K code of the RIN is changed to 2.

Separation of RINs may be conducted in accordance with prevailing rules and regulations, as currently provided in 40 C.F.R. §80.1129 and 40 C.F.R. §80.1429. RINs generated in accordance with the invention may be separated and subsequently traded.

It should be understood that the regulations under EISA, including RIN requirements and the criteria for categorization of a fuel under a particular fuel category, such as life cycle GHG emission thresholds, are described herein in accordance with current regulations and that the invention is not limited to current rules and will provide benefits in relation to subsequent rule changes thereof.

Low Carbon Fuel Standard

The beneficial GHG emissions reductions achieved by the present invention also can provide a methodology for meeting low carbon fuel standards established by jurisdictions within the United States or other government authorities. The credit, which includes a certificate, may be associated with the fermentation based fuel, or a fuel derived therefrom, and represents or is proportional to the amount of life cycle GHG emissions reduced measured relative to a gasoline baseline. As set forth previously, the life cycle GHG emissions under low carbon fuel standards are often referred to as carbon intensity or CI. Preferably, the credit is associated with the improved production process for making an alcohol.

California's LCFS currently requires that all mixes of fuel that oil refineries and distributors sell in the Californian market meet in aggregate the established targets for GHG emissions reductions. California's LCFS requires increasing annual reductions in the average life cycle emissions of most transportation fuels, up to a reduction of at least 10% in the carbon intensity, which is a measure of the life cycle GHG emissions, by 2020. Targets can be met by trading of credits generated from the use of fuels with a lower GHG emission value than gasoline baseline. Similar legislation has been implemented by the province of British Columbia, Canada, the United Kingdom and by the European Union.

British Columbia approved a Renewable and Low Carbon Fuel Requirements Act, which requires parties who manufacture or import the fuel into the province ensure that the renewable content and the average carbon intensity of the fuel they supply meets levels set by regulations. Fuel suppliers are required to submit annual reports regarding the renewable fuel content and carbon intensity of the transportation fuels they supply. The province allows transfers of GHG credits between fuel suppliers to provide flexibility in meeting the requirements of the regulation (http://www2.gov.bc.ca/).

In the European Union, GHG emissions are regulated by a Fuel Quality Directive, 98/70/EC. In April 2009, Directive 2009/30/EC was adopted which revises the Fuel Quality Directive 98/70/EC. The revisions include a new element of legislation under Article 7a that requires fuel suppliers to reduce the GHG intensity of energy supplied for road transport (Low Carbon Fuel Standard). In particular, Article 7a specifies that this reduction should amount to at least 6% by 31 Dec. 2020, compared to the EU-average level of life cycle GHG emissions per unit of energy from fossil fuels in 2010. According to the Fuel Quality Directive, fuel/energy suppliers designated by member states of the European Union are required to report to designated authorities on: (a) the total volume of each type of fuel/energy supplied, indicating where the fuel/energy was purchased and its origin; and (b) the life cycle GHG emissions per unit of energy. The European Union has also promoted the use of biofuels through a Biofuel Directive (2003/30/EC), which mandates countries across the EU to displace certain percentages of transportation fuel with biofuels by target dates.

The United Kingdom has a Renewable Transport Fuel Obligation in which biofuel suppliers are required to report on the level of carbon savings and sustainability of the biofuels they supplied in order to receive Renewable Transport Fuel Certificates (RTFCs). Suppliers report on both the net GHG savings and the sustainability of the biofuels they supply according to the appropriate sustainability standards of the feedstocks from which they are produced and any potential indirect impacts of biofuel production, such as indirect land-use change or changes to food and other commodity prices that are beyond the control of individual suppliers. Suppliers that do not submit a report will not be eligible for RTFCs.

Certificates or credits can be claimed when renewable fuels are supplied and fuel duty is paid on them. At the end of the obligation period, these certificates may be redeemed to the RTFO Administrator to demonstrate compliance. Certificates can be traded, therefore, if obligated suppliers do not have enough certificates at the end of an obligation period they have to ‘buy-out’ the balance of their obligation by paying a buy-out price.

The present invention will be further illustrated in the following examples. However, it is to be understood that the examples below are for illustrative purposes only and should not be construed to limit the current invention in any manner. Further, it should be appreciated that the values used in the GHG life cycle calculations in the examples below may be updated over time by regulatory bodies. Accordingly, the standards for determining GHG life cycle values presented herein and calculations made thereunder are exemplary and merely reflect GHG accounting modeling methods used currently by regulators.

EXAMPLES Example 1 Reducing the Life Cycle GHG Emissions Associated with a Liquid Fuel by Collecting Biogenic Carbon Dioxide and Displacing Geologic Carbon Dioxide in Enhanced Oil or Gas Recovery

This example illustrates how a dry mill ethanol plant processing sorghum to ethanol can reduce its life cycle GHG emissions to below 50% of the gasoline baseline value used by the EPA under EISA by collecting biogenic carbon dioxide and displacing geologic carbon dioxide in or associated with enhanced oil or gas recovery. Advantageously, by meeting this GHG emission threshold, the ethanol qualifies for D5 RINs under the RFS. In this example, the life cycle GHG emissions of the fuels are compared using EPA GHG emissions methods and their 2022 scenario for certain GHG values (see EPA-HQ-OAR-2011-0542; FRL-9680-8, Notice of Data Availability Concerning Renewable Fuels Produced From Grain Sorghum Under the RF Program). The percentage GHG reductions relative to the gasoline baseline are calculated are based on a midpoint of a range of results in accordance with Federal Register, Vol. 77, No. 113, Proposed Rules (Jun. 12, 2012), “Notice of Data Availability Concerning Renewable Fuels Produced From Grain Sorghum Under the RFS Program”, page 34923, http://www.gpo.gov/fdsys/pkg/FR-2012-06-12/pdf/2012-13651.pdf, accessed Jun. 12, 2012.

(a) Life Cycle GHG Emissions Reductions without Biogenic Carbon Dioxide Collection and Displacement of Geologic Carbon Dioxide

The following illustrates the GHG emissions associated with ethanol production from sorghum in which biogenic carbon dioxide is released to the atmosphere, also referred to as a production process baseline. As shown below, when biogenic carbon dioxide is released to the atmosphere rather than collected and used to displace geologic carbon dioxide in an enhanced oil or gas recovery, the GHG emissions of the fuel are only reduced by 32% relative to the gasoline baseline. The gasoline baseline is a 2005 gasoline baseline value as set out in EPA-HQ-OAR-2011-0542; FRL-9680-8, supra.

In the life cycle of the fuel, carbon dioxide from the atmosphere is sequestered into the starch by the action of photosynthesis. However, energy is used and GHG emissions occur during the course of the feedstock production and harvesting, the transport to the ethanol plant, the production process itself, the transport of the products to market, and the combustion of the fuel. There is also a GHG emissions increase associated with implied indirect land use changes and other indirect impacts associated with the feedstock markets. The direct carbon dioxide emissions from the fermentation of the starch and from the combustion of the ethanol are offset by carbon dioxide sequestered in the starch by photosynthesis.

Provided below is a summary of the GHG emissions that result from the ethanol production process itself. The ethanol plant uses natural gas and non-renewable electricity, and the use of these energy sources leads to the life cycle GHG emissions in Table 4.

TABLE 4 GHG emissions from the ethanol production process Emissions from BTU/gal Value for emissions, fuel use, g ethanol g CO₂eq/MMBTU fuel CO₂eq/MMBTU produced used ethanol produced Natural gas use 17,341 68,575 15,647 Biogas use 0 364 0 Non-renewable 2,235 219,824 6,465 electricity use TOTAL 19,576 22,111

The life cycle GHG emissions for ethanol production from sorghum throughout the fuel life cycle are shown below in Table 5 and compared to those of a 2005 gasoline baseline (see HQ-OAR-2011-0542; FRL-9680-8, supra). The life cycle emissions are for grain sorghum ethanol produced in plants that use natural gas and produce an industry average of 92% wet distillers grain.

TABLE 5 Life cycle GHG emissions for the gasoline baseline and the production process baseline using grain sorghum as the feedstock (g CO₂eq/MMBTU) Grain sorghum 2005 gasoline ethanol (production Fuel Process baseline process baseline) Net agriculture — 12,698 Land use change — 27,620 Fuel production 19,200 22,111 Fuel and feedstock transport * 3,661 Tailpipe emissions 79,004 880 Total emissions 98,204 66,971 Percent savings vs. gasoline — 32% * Emissions included in fuel production stage

As can be seen in Table 5, when the emission values from each stage of the fuel life cycles are summed, the net carbon dioxide emissions values are 98,204 g CO₂ eq/MMBTU for gasoline and 66,971 g CO₂ eq/MMBTU for ethanol produced from sorghum without any biogenic carbon dioxide collection and displacement of geologic carbon dioxide with the collected biogenic carbon dioxide in an enhanced oil or gas recovery site. This represents a GHG emissions reduction of only 32% relative to the gasoline baseline for ethanol produced from sorghum. Thus, the emissions fall short of the requirement to achieve D5 RINs, or 50% GHG savings relative to the gasoline baseline.

(b) Life Cycle GHG Emissions Reductions with Biogenic Carbon Dioxide Collection and Displacement of Geologic Carbon Dioxide

The following illustrates that the decrease in emissions associated with the use of the invention permits an ethanol plant to achieve a 56% savings in life cycle GHG emissions associated with ethanol production relative to the gasoline baseline. This is a significant improvement from the 32% life cycle GHG savings for ethanol production without the displacement of the invention.

In this example, the total quantity of biogenic carbon dioxide produced from the ethanol fermentation using sorghum as the feedstock is 2,899 g carbon dioxide per gallon of ethanol, or 38,145 g carbon dioxide per MMBTU of ethanol produced. The ethanol plant then collects 80 wt % of the biogenic carbon dioxide and uses it to displace geologic carbon dioxide in an enhanced oil or gas recovery site. In this example, the biogenic carbon dioxide is transported to the enhanced oil or gas recovery site using a fungible carbon dioxide pipeline. It should be appreciated that, in terms of the beneficial environmental attributes associated with the use of carbon dioxide, it is immaterial whether the displacement of geologic carbon dioxide occurs in a fungible carbon dioxide pipeline, or in a specific enhanced oil or gas recovery site that draws carbon dioxide from that pipeline. Thus, certain carbon dioxide withdrawn from such a pipeline will still be considered to possess the GHG emission attributes set out below.

The ethanol plant uses natural gas and renewable electricity in the production process (per the baseline), and additional electricity and diesel fuel for the production and transport of the carbon dioxide by truck to the enhanced oil or gas recovery site. The additional usage of electricity is assumed to be 163 kWhr/ton of CO₂ collected, and the usage of diesel is based on a 390 mile one-way distance, 5 miles per gallon diesel usage, and 17.2 ton CO₂/truck. The assumed emission factor for electricity is 219,824 g CO₂ eq/MMBTU, and the assumed factor for diesel is 97,006 g CO₂ eq/MMBTU. The total quantity of biogenic carbon dioxide collected is 30,516 g carbon dioxide per MMBTU of ethanol produced (80% of 38,145).

The carbon dioxide losses associated with collection, purification, compression and transport are also accounted for and a summary of the net energy inputs to each of these operations are as follows:

TABLE 6 Carbon dioxide emissions from purification, compression and transport of biogenic carbon dioxide Emissions from fuel Usage Value for use, g BTU/ton of emissions, g CO₂eq/MMBTU CO₂ CO₂eq/MMBTU ethanol produced Non-renewable 556,156 219,824 3,731 electricity use Diesel for transport 1,174,426 97,006 3,477 TOTAL 1,730,582 7,207

The value for the total net reduction in emissions due to displacement of geologic carbon dioxide for biogenic carbon dioxide, taking into account the collection, purification, compression and transport, is 23,308 g CO₂ eq/MMBTU ethanol. The value is arrived at by subtracting the 7,207 g CO₂ eq/MMBTU emission due to these losses, from the net GHG saving of 30,514 g CO₂ eq/MMBTU of ethanol emission due to displacement.

The net carbon dioxide emissions and savings throughout the full fuel life cycle implementing the invention are shown in Table 7 below (rightmost column). The values for the GHG savings are shown in brackets (negative emission). The net carbon dioxide emission value for the full fuel life cycle with displacement of biogenic carbon dioxide for geologic carbon dioxide is 43,662 g CO₂ eq/MMBTU ethanol, while the carbon dioxide emission value for the production process baseline is 66,971 g CO₂ eq/MMBTU ethanol. This represents a percent reduction verses the gasoline baseline of 56%, which is a significant increase relative to the 32% reduction when there is no such displacement.

The percent changes in life cycle emissions with and without implementation of the invention are depicted in FIG. 1.

TABLE 7 Comparison of life cycle GHG emissions for gasoline baseline, production process baseline, emissions due to the displacement of the invention and full life cycle emissions of the fuel with the displacement Grain sorghum ethanol with displacement of geologic carbon Grain sorghum dioxide with ethanol baseline biogenic (production carbon dioxide 2005 process in accordance with gasoline baseline; g the invention Fuel Process baseline CO₂eq/MMBTU) (g CO₂eq/MMBTU) Net agriculture — 12,698 12,698 Land use change — 27,620 27,620 Fuel production 19,200 22,111 22,111 Fuel and feedstock * 3,661  3,661 Transport Tailpipe emissions 79,004 880   880 Net change from (23,308) implementation of the invention Total emissions 98,204 66,971 43,662 Midpoint life cycle — 32% 56% GHG reduction percent compared to gasoline * Emissions included in fuel production stage

Example 2 Using the Invention to Increase the Generation of LCFS Credits in a Biogas Derived Fuel

The present invention also allows a landfill gas collection operation using biomethane from landfill organic waste to make compressed natural gas (CNG) for vehicle use, and achieve a greater degree of LCFS credit generation from the operation, as shown below. The calculations are based on California's LCFS regulations.

(a) Baseline Emissions for Natural Gas Based CNG

The California Air Resources Board (CARB) has determined life cycle GHG emissions values for CNG derived from natural gas and CNG from landfill biomethane as in Table 8 below.

TABLE 8 Life cycle GHG emissions values for CNG derived from natural gas and biomethane LCFS Credits Emissions Value Generated by Fuel Fuel (g CO₂eq/MJ) Use (g CO₂eq/MJ) California Gasoline 95.86 0 CNG derived from natural gas 67.7 28.16 CNG derived from landfill 11.3 84.56 biomethane

(b) Emission Reductions Due to the Invention

Anaerobic digestion of organic material in a landfill operation produces biomethane and carbon dioxide, although other gases such as hydrogen and impurities may be generated as well. The total quantity of carbon dioxide produced from the fermentation of organic material in the landfill operation is 49.4 g CO₂ eq per MJ of methane produced.

According to this example, the landfill operation implements the invention by collecting 80 wt % of the carbon dioxide evolved during anaerobic digestion and using the carbon dioxide to displace geologic carbon dioxide in an enhanced oil or gas recovery operation. The operation uses renewable electricity in the production process, and diesel fuel for the transport of the carbon dioxide by truck to the enhanced oil or gas recovery operation. The total quantity of biogenic carbon dioxide collected is 39.5 g carbon dioxide per MJ of biogas produced (80% of 49.4 g CO₂ eq/MJ), and the displacement of geologic carbon dioxide by biogenic carbon dioxide leads to a reduction of carbon dioxide emissions of 39.5 g CO₂ eq per MJ of biogas produced.

The energy used and the GHG emissions that occur as a result of the carbon dioxide collection, compression and transport are also accounted for. The GHG impact of these operations leads to an increase of 8.56 g CO₂ eq per MJ of biogas. A summary of the net energy inputs to and emissions associated with the collection, compression, and transport operations are as follows:

TABLE 9 Carbon dioxide emissions from purification, compression and transport of biogenic carbon dioxide CARB Emissions MJ value for from fuel energy/MJ emissions, g use, g CO₂eq/MJ biogas CO₂eq/MJ biogas produced Renewable electricity use 0.023 0 0 Diesel for transport 0.090 94.71 8.56 TOTAL 0.114 8.56

The net life cycle GHG savings associated with the implementation of the invention is 30.94 g CO₂ eq/MJ biogas (savings of 39.50 g CO₂ eq/MJ offset by an increase of 8.56 g CO₂ eq/MJ).

(c) Combined Emissions from Fuel Life Cycle

The decrease in emissions associated with the use of the invention in this example permits the landfill to generate additional LCFS credits equal to 30.94 g CO₂ eq/MJ of CNG-based biogas, when compared to CNG based biogas without use of the invention. The LCFS credit value of the CNG based biogas is increased from 84.56 g CO₂ eq/MJ to 115 g CO₂ eq/MJ, an increase of 36.6% by use of the invention. Table 10 below summarizes the baselines and the changes in g CO₂ eq/MJ.

TABLE 10 Comparison of the emissions values and LCFS credits for California gasoline, CNG derived from natural gas and CNG derived from landfill biogas with displacement of biogenic carbon dioxide LCFS credits Emissions generated by value fuel use Fuel (g CO₂eq/MJ) (g CO₂eq/MJ) California gasoline 95.86 0 CNG derived from natural gas 67.7 28.16 CNG derived from landfill biomethane 11.3 84.56 Incremental impact of CO₂ (39.5) 39.50 sequestration Incremental impact of CO₂ processing 8.56 (8.56) and transport CNG derived from landfill biomethane (19.64) 115.50 with invention

Example 3 Reducing the Life Cycle GHG Emissions Associated with a Liquid Fuel by Using Methane Having Reduced Life Cycle GHG Emissions

The present invention also enables a liquid fuel production facility, such as an ethanol production facility, to reduce the life cycle GHG emissions of the liquid fuel by using methane having reduced life cycle GHG emissions to provide energy to the production facility or associated utilities.

According to this example, biomethane and biogenic carbon dioxide is generated in a landfill by anaerobic digestion and the biomethane is then separated from the carbon dioxide. The carbon dioxide that is collected is used in an enhanced oil or gas recovery operation to displace geologic carbon dioxide, while the biomethane is supplied for use in the liquid fuel production facility or utilities to generate energy in the form of heat or electricity. The decrease in emissions associated with the use of such low GHG methane for energy production permits the liquid fuel production facility to generate a liquid fuel having a D5 RIN. In this example, the liquid fuel is ethanol produced from sorghum.

(a) Introducing the Biomethane to a Pipeline and Withdrawing Methane Having Reduced GHG Emissions at the Liquid Fuel Production Facility

In this example, the biomethane is introduced to a natural gas pipeline that supplies methane to the ethanol fuel production facility.

Since the pipeline is fed by natural gas, as well as biomethane, the methane withdrawn may not contain actual molecules from the original organic material from which the biomethane is derived, but rather the energy equivalent value of the biomethane. With respect to biomethane used for electricity generation in a facility, government authorities have recognized that it is immaterial, in terms of the beneficial environmental attributes associated with the use of biomethane, whether the displacement of fossil fuel occurs in a fungible natural gas pipeline, or in a specific fuel production facility that draws methane from that pipeline. Thus, methane withdrawn from such a pipeline will still be considered to possess the GHG emission reductions set out in Example 3(c) below.

The amount of biomethane fed to the natural gas pipeline and the amount of methane withdrawn from such a pipeline is the same and is determined by gas metering. A gas meter is placed at the point on the pipeline where biomethane is introduced and another meter is placed at the point on the pipeline where methane is withdrawn for use in the fuel production facility. A contract is in place which sets out the amount of biomethane fed to the pipeline by the landfill operation and the amount of methane to be withdrawn for use at the ethanol production facility.

(b) Using Methane Having Reduced GHG Emissions to Supply Energy to the Ethanol Production Facility

The following compares the life cycle GHG emissions associated with ethanol production from sorghum using methane derived from the following processes:

(i) methane derived from biogas in which the carbon dioxide that is separated from the biogas is released to the atmosphere; and (ii) methane derived from biogas in which the carbon dioxide that is separated from the biogas is supplied to an enhanced oil or gas recovery site to displace geologic carbon dioxide, as set out in Example 3(a) above.

Provided below in Table 11 and Table 12 is a summary of the GHG emissions that result from the ethanol production process using the methane derived from biogas from each of the above sources.

As can be seen in Table 12 below, when the emission values from each stage of the fuel life cycle are summed, the net carbon dioxide emissions value for ethanol production using methane derived from biogas in which carbon dioxide is released to the atmosphere is 51,407 g CO₂ eq/MMBTU. This represents a GHG emission reduction of only 48% relative to the gasoline baseline. This value is not sufficient for the ethanol produced in the fuel production facility to qualify for a D5 RIN. (As discussed previously, such a RIN requires a 50% reduction relative to the gasoline baseline).

TABLE 11 GHG emissions from the ethanol production process using methane derived from biogas without CO₂ collection Emissions from fuel use, g BTU/gal  Value for emissions, CO₂eq/MMBTU ethanol g CO₂eq/MMBTU fuel ethanol produced used produced Natural gas use — — — Biogas use 17,341 364 83 Non-renewable 2,235 219,824 6,465 electricity use TOTAL 19,576 6,548

TABLE 12 Life cycle GHG emissions for grain sorghum ethanol process using methane derived from biogas without CO₂ collection Grain sorghum Grain sorghum 2005 gasoline ethanol ethanol using Fuel Process baseline baseline biogas Net agriculture — 12,698 12,698 Land Use Change — 27,620 27,620 Fuel Production 19,200 22,111 6,548 Fuel and Feedstock * 3,661 3,661 Transport Tailpipe emissions 79,004 880 880 Total emissions 98,204 66,971 51,407 **Midpoint life — 32% 48% cycle GHG reduction percent compared to gasoline * Emissions included in fuel production stage

(c) Production of Methane Having Reduced Life Cycle GHG Emissions

The life cycle GHG emissions of the methane used in an ethanol fuel production process are reduced relative to a biomethane production process baseline by displacing geologic carbon dioxide with biogenic carbon dioxide collected from biogas as described in Table 13. The assumptions around the usage and emission intensity of both diesel and electricity are the same as outlined in Example 1. The biomethane production process baseline refers to the life cycle GHG emissions associated with a biogas production process conducted under identical conditions except the biogenic carbon dioxide that is separated from the biomethane is released to the atmosphere.

TABLE 13 GHG Emissions from the process of purification, compression and transport of biogenic carbon dioxide Emissions Value for from fuel use, g emissions, CO₂eq/MMBTU Usage g CO₂eq/ ethanol BTU/ton CO₂ MMBTU produced Natural gas use — — — Biogas use — — — Non-renewable 556,156 219,824 1,162 electricity use Diesel for transport 1,1744,26 97,006 1,083 TOTAL 293,927 2,245

As stated in Example 2, 80 wt % of the carbon dioxide produced during anaerobic digestion is collected. The total quantity of biogenic carbon dioxide collected is 41,667 g carbon dioxide per MMBTU of biogas produced (80% of the 52,084 CO₂ eq/MMBTU which is produced in the landfill operation). This equates to a value of 9,507 g CO₂ eq per MMBTU of ethanol produced. The GHG emissions associated with carbon dioxide collection, compression and transport account for an increase of 2,245 g CO₂ eq/MMBTU of ethanol (Table 13).

The value for the total net reduction from the invention is 7,262 g CO₂ eq/MMBTU ethanol. The value is obtained by subtracting the 2,245 g CO₂ eq/MMBTU emission due to these losses, from the net GHG saving of 9,507 g CO₂ eq/MMBTU of ethanol emission due to displacement.

Table 14 below summarizes the baselines and the changes. It is noted that when using methane in a fuel production facility that is derived from biogas in which the carbon dioxide that is separated from the biomethane is supplied to enhanced oil or gas recovery site to displace geologic carbon dioxide, the sum of the GHG emissions is 44,144 g CO₂ eq/MMBTU. This represents a GHG emissions reduction of 55% relative to the gasoline baseline. Due to these significant life cycle GHG emission reductions relative to the gasoline baseline, the ethanol produced from the fuel production facility meets the GHG emission reduction threshold needed to qualify for a D5 RIN.

The percent changes in life cycle emissions with and without implementation of the invention are depicted in FIG. 2.

TABLE 14 Comparison of the emissions values for the gasoline baseline, methane derived from natural gas and methane derived from landfill biogas with displacement of biogenic carbon dioxide Grain sorghum ethanol using biomethane from which biogenic carbon dioxide is collected and Grain sorghum used to displace ethanol using geologic carbon biomethane dioxide in 2005 gasoline Grain sorghum production accordance with Fuel Process baseline ethanol baseline process baseline the invention Net agriculture — 12,698 12,698 12,698 Land use change — 27,620 27,620 27,620 Fuel production 19,200 22,111 6,548  6,548 Fuel and feedstock * 3,661 3,661  3,661 transport Tailpipe emissions 79,004 880 880   880 Change from — — —  (7,262) implementation of the invention Total emissions 98,204 66,971 51,407 44,144 **Midpoint life — 32% 48% 55% cycle GHG reduction percent compared to gasoline * Emissions included in fuel production stage 

1. A method for reducing life cycle GHG emissions associated with production of biomethane, said method comprising: (i) anaerobically digesting organic material to produce biogas comprising biomethane and biogenic carbon dioxide; (ii) separating the biomethane and biogenic carbon dioxide; (iii) collecting an amount of the biogenic carbon dioxide generated from the step of separating; and (iv) supplying the biogenic carbon dioxide from step (iii) for use in one or more enhanced oil or gas recovery sites for displacement of geological carbon dioxide, wherein the life cycle GHG emissions associated with the production or use of the biomethane are reduced by at least 1.5 g CO₂ eq/MJ relative to a biomethane production process baseline as a result of the displacement of geologic carbon dioxide.
 2. The method of claim 1, wherein the displacement results from taking out of use a first amount of geologic carbon dioxide at the one or more enhanced oil or gas recovery sites and supplying an amount of biogenic carbon dioxide at the one or more enhanced oil or gas recovery sites to substitute the first amount of geologic carbon dioxide.
 3. A method for reducing life cycle GHG emissions associated with production of biomethane, said method comprising: (i) anaerobically digesting organic material to produce biogas comprising biomethane and biogenic carbon dioxide; (ii) separating the biomethane and biogenic carbon dioxide; (iii) collecting an amount of the biogenic carbon dioxide generated from the step of separating; and (iv) reducing the life cycle GHG emissions associated with the biomethane, said reducing being achieved at least in part by a displacement of geologic carbon dioxide with the biogenic carbon dioxide from step (iii), said displacement resulting from: (a) introducing the biogenic carbon dioxide into an apparatus for transporting carbon dioxide to one or more enhanced oil or gas recovery sites that used or are using geologic carbon dioxide; (b) supplying the biogenic carbon dioxide for use in one or more enhanced oil or gas recovery sites that used or are using geologic carbon dioxide; or (c) both (a) and (b), wherein the life cycle GHG emissions associated with the production or use of the biomethane are reduced by at least about 1.5 g CO₂ eq/MJ as a result of the displacement of geologic carbon dioxide.
 4. The method of claim 1, wherein the life cycle GHG emissions associated with the production or use of the biomethane are reduced by between about 5 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ relative to a biomethane production process baseline.
 5. The method of claim 2, wherein the life cycle GHG emissions associated with the production or use of the biomethane are reduced by between about 5 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ relative to a biomethane production process baseline.
 6. The method of claim 3, wherein the life cycle GHG emissions associated with the production or use of the biomethane are reduced by between about 5 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ relative to a biomethane production process baseline.
 7. A method to reduce the life cycle GHG emissions associated with production of a liquid fuel or fuel intermediate, said method comprising: (i) producing sugar from plant derived organic material and converting the sugar to the liquid fuel or fuel intermediate in a fuel production facility; and (ii) using methane to supply energy to the fuel production facility or associated utilities, wherein said methane has associated with it life cycle GHG emissions that are reduced relative to a biomethane production process baseline as a result of carrying out the method of claim
 1. 8. The method of claim 7, wherein said methane having associated reduced life cycle GHG emissions was provided by a third party.
 9. The method of claim 7, wherein the methane used to supply energy to the fuel production facility or associated utilities is withdrawn from a natural gas pipeline containing methane from sources other than anaerobic digestion of organic material.
 10. The method of claim 1, wherein the biogenic carbon dioxide supplied to the one or more enhanced oil or gas recovery sites displaces the use of or demand for geologic carbon dioxide in said one or more enhanced oil or gas recovery sites.
 11. The method of claim 7, wherein the methane supplies energy in the form of heat or electricity.
 12. The method of claim 7, wherein a renewable fuel credit is associated with the liquid fuel or fuel intermediate.
 13. The method of claim 7, wherein a renewable fuel credit associated with the liquid fuel or fuel intermediate and wherein the renewable fuel credit is a D5 RIN or a D3 RIN.
 14. The method of claim 7, wherein the life cycle GHG emissions associated with the liquid fuel or fuel intermediate are reduced to a level of at least 40% relative to a gasoline baseline.
 15. The method of claim 7, wherein the life cycle GHG emissions associated with the liquid fuel or fuel intermediate are reduced to a level of at least 50% relative to a gasoline baseline.
 16. The method of claim 7, wherein the sugar is converted to the fuel or fuel intermediate by a fermentation that produces biogenic carbon dioxide and wherein the method further comprises collecting an amount of biogenic carbon dioxide produced from the step of fermenting and supplying the biogenic carbon dioxide that is collected for use in one or more enhanced oil or gas recovery sites for displacement of geological carbon dioxide.
 17. The method of claim 7, wherein the life cycle GHG emissions associated with the methane are reduced by between about 5 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ relative to a biomethane production process baseline as a result of the displacement of geologic carbon dioxide.
 18. A method to reduce the life cycle GHG emissions associated with production of a liquid fuel or fuel intermediate, said method comprising: (i) producing sugar from plant derived organic material and converting the sugar to the liquid fuel or fuel intermediate in a fuel production facility; and (ii) receiving methane to supply energy in any part of the fuel production facility or associated utilities, wherein said methane has associated with it life cycle GHG emissions that are reduced relative to a biomethane production process baseline as a result of producing the methane by a process comprising: (a) anaerobically digesting organic material to produce biogas comprising methane and biogenic carbon dioxide; (b) separating the methane and biogenic carbon dioxide; (c) collecting an amount of the biogenic carbon dioxide generated from the step of separating; (d) supplying the biogenic carbon dioxide from step (c) for use in one or more enhanced oil or gas recovery sites for displacement of geologic carbon dioxide; and (e) supplying the biomethane to an apparatus for delivering methane to one or more fuel production facilities.
 19. The method of claim 18, wherein the life cycle GHG emissions associated with the methane are reduced by between about 5 g CO₂ eq/MJ and about 35 g CO₂ eq/MJ relative to a biomethane production process baseline as a result of the displacement of geologic carbon dioxide.
 20. A method for producing a liquid fuel comprising the steps of blending with gasoline the liquid fuel or fuel intermediate having reduced life cycle GHG emissions according to claim
 18. 21. The method of claim 18, wherein a third party carries out steps (a)-(e).
 22. A method comprising (i) receiving carbon dioxide at an enhanced oil or gas recovery site, said carbon dioxide being withdrawn from an apparatus into which carbon dioxide produced by claim 1 is fed; and (ii) using the received carbon dioxide to displace geologic carbon dioxide at the site.
 23. The method of claim 22, wherein a third party supplies the carbon dioxide received at the enhanced oil or gas recovery site.
 24. A method comprising: (a) receiving carbon dioxide at an enhanced oil or gas recovery site, said carbon dioxide being withdrawn from an apparatus into which biogenic carbon dioxide derived from an anaerobic digestion has been fed and wherein the received carbon dioxide has the GHG emission attributes of the biogenic carbon dioxide derived from the anaerobic digestion; and (b) using the received carbon dioxide to displace geologic carbon dioxide.
 25. The method of claim 24, further comprising causing a third party to feed the carbon dioxide derived from the anaerobic digestion to said apparatus.
 26. The method of claim 24, wherein the GHG emission attributes of the withdrawn carbon dioxide are set out in written documentation.
 27. The method of claim 26, wherein the written documentation comprises data relating to a life cycle GHG analysis, which life cycle GHG emission analysis a GHG emission savings resulting from the displacement of geologic carbon dioxide and wherein the written documentation is in computer readable format. 